Indiana Michigan Power 10-K 24 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015USD ($)shares
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float | $	$ 26,011,055,215
Entity Common Stock, Shares Outstanding	491,052,581
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	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Vertically Integrated Utilities	$ 9,069.9	$ 9,396.8	$ 9,346.6
Transmission and Distribution Utilities	4,392	4,552.6	4,279.1
Generation and Marketing	2,866.7	2,384.3	1,208
Other Revenues	124.6	44.9	(20.2)
TOTAL REVENUES	16,453.2	16,378.6	14,813.5
Expenses
Fuel and Other Consumables Used for Electric Generation	3,348.1	4,271.8	4,068.3
Purchased Electricity for Resale	2,760.1	2,085.9	1,490.8
Other Operation	2,703.9	2,766.6	2,448.4
Maintenance	1,325.3	1,328	1,163.2
Asset Impairments and Other Related Charges	0	0	226.4
Depreciation and Amortization	2,009.7	1,897.6	1,712.5
Taxes Other Than Income Taxes	972.6	901.3	881.4
TOTAL EXPENSES	13,119.7	13,251.2	11,991
OPERATING INCOME (LOSS)	3,333.5	3,127.4	2,822.5
Other Income (Expense):
Interest and Investment Income	7.9	7.4	57.9
Carrying Costs Income	23.5	33.2	30.2
Allowance for Equity Funds Used During Construction	131.9	102.9	72.7
Interest Expense	(873.9)	(868)	(890)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	2,622.9	2,402.9	2,093.3
Income Tax Expense (Credit)	919.6	902.6	677.7
Equity Earnings (Loss) of Unconsolidated Subsidiaries	65.3	90.2	58.3
Income from Continuing Operations	1,768.6	1,590.5	1,473.9
Income from Discontinued Operations, Net of Tax	283.7	47.5	10.3
NET INCOME (LOSS)	2,052.3	1,638	1,484.2
Net Income Attributable to Noncontrolling Interests	5.2	4.2	3.7
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 2,047.1	$ 1,633.8	$ 1,480.5
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	490,340,522	488,592,997	486,619,555
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 3.59	$ 3.24	$ 3.02
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0.58	0.10	0.02
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 4.17	$ 3.34	$ 3.04
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	490,574,568	488,899,840	487,040,956
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 3.59	$ 3.24	$ 3.02
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	0.58	0.10	0.02
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 4.17	$ 3.34	$ 3.04
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	$ 2,805.6	$ 2,899.4	$ 3,059.6
Sales to AEP Affiliates	147.8	144.5	347.5
Other Revenues	10.1	9.2	10.3
TOTAL REVENUES	2,963.5	3,053.1	3,417.4
Expenses
Fuel and Other Consumables Used for Electric Generation	675.9	813.4	769.9
Purchased Electricity for Resale	395.2	456.6	232.7
Purchased Electricity from AEP Affiliates	0	4.7	830.9
Other Operation	405.4	427.7	312
Maintenance	263.3	259.3	273.2
Asset Impairments and Other Related Charges	0	0	39.3
Depreciation and Amortization	388.8	400.9	342.6
Taxes Other Than Income Taxes	124.1	122.3	110.5
TOTAL EXPENSES	2,252.7	2,484.9	2,911.1
OPERATING INCOME (LOSS)	710.8	568.2	506.3
Other Income (Expense):
Interest Income	1.4	1.6	2.4
Carrying Costs Income	1.2	3	8.1
Allowance for Equity Funds Used During Construction	13.8	7.1	2.3
Interest Expense	(192.3)	(209.6)	(193)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	534.9	370.3	326.1
Income Tax Expense (Credit)	194.3	154.9	132.9
NET INCOME (LOSS)	340.6	215.4	193.2
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	2,073.3	2,149.1	2,022.3
Sales to AEP Affiliates	27.4	4.2	219.4
Other Revenues - Affiliated	78.8	94.4	122.3
Other Revenues	6.7	2	2.9
TOTAL REVENUES	2,186.2	2,249.7	2,366.9
Expenses
Fuel and Other Consumables Used for Electric Generation	336.3	476.6	434.1
Purchased Electricity for Resale	195.8	96.8	151.4
Purchased Electricity from AEP Affiliates	232.1	270	433.2
Other Operation	553.4	586	564
Maintenance	212	228.5	195.9
Depreciation and Amortization	198.4	200.2	177.7
Taxes Other Than Income Taxes	88.3	86.4	88.7
TOTAL EXPENSES	1,816.3	1,944.5	2,045
OPERATING INCOME (LOSS)	369.9	305.2	321.9
Other Income (Expense):
Interest Income	9.6	4.6	8.5
Allowance for Equity Funds Used During Construction	11.6	18.9	19.9
Interest Expense	(90.2)	(93.5)	(97.7)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	300.9	235.2	252.6
Income Tax Expense (Credit)	96.1	79.6	75.1
NET INCOME (LOSS)	204.8	155.6	177.5
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	3,056.1	3,204.9	3,562.2
Sales to AEP Affiliates	84.1	165.2	1,166.9
Other Revenues - Affiliated	0	0	18.1
Other Revenues	8.5	6.8	15.4
TOTAL REVENUES	3,148.7	3,376.9	4,762.6
Expenses
Fuel and Other Consumables Used for Electric Generation	0	0	1,496.9
Purchased Electricity for Resale	635	282	151.5
Purchased Electricity from AEP Affiliates	496.4	1,192.7	349.7
Amortization of Generation Deferrals	169.1	110.9	0
Other Operation	630.3	594.8	708
Maintenance	166.8	196	319.6
Asset Impairments and Other Related Charges	0	0	154.3
Depreciation and Amortization	217.5	213.7	382.6
Taxes Other Than Income Taxes	372.8	353.3	406.9
TOTAL EXPENSES	2,687.9	2,943.4	3,969.5
OPERATING INCOME (LOSS)	460.8	433.5	793.1
Other Income (Expense):
Interest Income	5.6	10	3.3
Carrying Costs Income	11.8	26.5	16.3
Allowance for Equity Funds Used During Construction	8.8	6.9	5
Interest Expense	(127.8)	(128.3)	(182)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	359.2	348.6	635.7
Income Tax Expense (Credit)	126.5	132.2	225.7
NET INCOME (LOSS)	232.7	216.4	410
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	1,331.4	1,340.3	1,277.7
Sales to AEP Affiliates	4.6	7.1	14.2
Other Revenues	3.2	4.2	3.6
TOTAL REVENUES	1,339.2	1,351.6	1,295.5
Expenses
Fuel and Other Consumables Used for Electric Generation	301.4	258	327.8
Purchased Electricity for Resale	316.9	385	246.1
Purchased Electricity from AEP Affiliates	0	11	36.9
Other Operation	268.4	262.8	225.5
Maintenance	104.6	108	107.1
Depreciation and Amortization	117.5	101	95.7
Taxes Other Than Income Taxes	37.2	37	45.2
TOTAL EXPENSES	1,146	1,162.8	1,084.3
OPERATING INCOME (LOSS)	193.2	188.8	211.2
Other Income (Expense):
Interest Income	0.4	0.2	1.1
Carrying Costs Income	0	0	0.3
Allowance for Equity Funds Used During Construction	8.8	3.1	4.2
Interest Expense	(58.6)	(54.6)	(53.1)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	143.8	137.5	163.7
Income Tax Expense (Credit)	51.3	50.6	65.9
NET INCOME (LOSS)	92.5	86.9	97.8
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	1,762.3	1,817.9	1,742.6
Sales to AEP Affiliates	16.6	26.3	51.8
Other Revenues	2	2.2	1.4
TOTAL REVENUES	1,780.9	1,846.4	1,795.8
Expenses
Fuel and Other Consumables Used for Electric Generation	570.6	650.4	630.5
Purchased Electricity for Resale	110.6	178.1	170
Purchased Electricity from AEP Affiliates	0	3.8	11.2
Other Operation	294.5	272.8	250.7
Maintenance	155.9	149.2	129.7
Depreciation and Amortization	192	185.1	179.2
Taxes Other Than Income Taxes	88.1	84.3	80.7
TOTAL EXPENSES	1,411.7	1,523.7	1,452
OPERATING INCOME (LOSS)	369.2	322.7	343.8
Other Income (Expense):
Interest Income	1.2	0.3	0.1
Allowance for Equity Funds Used During Construction	26.4	11.9	7.4
Interest Expense	(119.9)	(126.1)	(130.3)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	276.9	208.8	221
Income Tax Expense (Credit)	84.8	66.4	69.5
Equity Earnings (Loss) of Unconsolidated Subsidiaries	3.9	2.2	2.3
NET INCOME (LOSS)	196	144.6	153.8
Net Income Attributable to Noncontrolling Interests	3.7	4.2	4
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 192.3	$ 140.4	$ 149.8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income (Loss)	$ 2,052.3	$ 1,638	$ 1,484.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(4.9)	5.3	15.5
Securities Available for Sale, Net of Tax	(0.6)	0.9	2.6
Amortization of Pension and OPEB Deferred Costs, Net of Tax	1.2	4.8	21.9
Pension and OPEB Funded Status, Net of Tax	(25.7)	1.1	176.6
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(30)	12.1	216.6
TOTAL COMPREHENSIVE INCOME (LOSS)	2,022.3	1,650.1	1,700.8
Total Comprehensive Income Attributable to Noncontrolling Interest	5.2	4.2	3.7
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	2,017.1	1,645.9	1,697.1
Appalachian Power Co [Member]
Net Income (Loss)	340.6	215.4	193.2
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.3)	0.7	1.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.8)	(1.3)	1.4
Pension and OPEB Funded Status, Net of Tax	(5.7)	2.7	29.7
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(7.8)	2.1	32.8
TOTAL COMPREHENSIVE INCOME (LOSS)	332.8	217.5	226
Indiana Michigan Power Co [Member]
Net Income (Loss)	204.8	155.6	177.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.1	1.5	4.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0	0.2	0.7
Pension and OPEB Funded Status, Net of Tax	(3.5)	(0.5)	8.5
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(2.4)	1.2	13.4
TOTAL COMPREHENSIVE INCOME (LOSS)	202.4	156.8	190.9
Ohio Power Co [Member]
Net Income (Loss)	232.7	216.4	410
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(1.3)	(1.5)	(0.3)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0	0	12.5
Pension and OPEB Funded Status, Net of Tax	0	0	65.4
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1.3)	(1.5)	77.6
TOTAL COMPREHENSIVE INCOME (LOSS)	231.4	214.9	487.6
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	92.5	86.9	97.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.8)	(0.8)	(0.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.8)	(0.8)	(0.7)
TOTAL COMPREHENSIVE INCOME (LOSS)	91.7	86.1	97.1
Southwestern Electric Power Co [Member]
Net Income (Loss)	196	144.6	153.8
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	2	2.2	2.3
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1)	(0.9)	(0.3)
Pension and OPEB Funded Status, Net of Tax	(2.9)	(0.3)	7.4
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1.9)	1	9.4
TOTAL COMPREHENSIVE INCOME (LOSS)	194.1	145.6	163.2
Total Comprehensive Income Attributable to Noncontrolling Interest	3.7	4.2	4
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	$ 190.4	$ 141.4	$ 159.2

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flow Hedges, Tax	$ (2.6)	$ 2.9	$ 8.3
Securities Available for Sale, Tax	(0.3)	0.4	1.4
Amortization of Pension and OPEB Deferred Costs, Tax	0.6	2.6	11.8
Pension and OPEB Funded Status, Tax	(13.9)	0.6	95.1
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	0.4	0.9
Amortization of Pension and OPEB Deferred Costs, Tax	(1)	(0.7)	0.8
Pension and OPEB Funded Status, Tax	(3.1)	1.5	16
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.6	0.8	2.3
Amortization of Pension and OPEB Deferred Costs, Tax	0	0.1	0.4
Pension and OPEB Funded Status, Tax	(1.9)	(0.3)	4.6
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.7)	(0.8)	(0.2)
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	6.7
Pension and OPEB Funded Status, Tax	0	0	35.2
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.4)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	1.1	1.2	1.2
Amortization of Pension and OPEB Deferred Costs, Tax	(0.5)	(0.5)	(0.1)
Pension and OPEB Funded Status, Tax	$ (1.6)	$ (0.2)	$ 4

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Appalachian Power Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member]Appalachian Power Co [Member]	Common Stock [Member]Indiana Michigan Power Co [Member]	Common Stock [Member]Ohio Power Co [Member]	Common Stock [Member]Public Service Co Of Oklahoma [Member]	Common Stock [Member]Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member]Ohio Power Co [Member]	Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member]	Retained Earnings [Member]		Retained Earnings [Member]Appalachian Power Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member]	Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Southwestern Electric Power Co [Member]
Common Stock, Dividends, Per Share, Declared	$ 1.95
Beginning Balance at Dec. 31, 2012	$ 15,237.5	$ 3,052.6	$ 1,803.8	$ 4,525.7	$ 916.2	$ 2,021.5	$ 3,289	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,049	$ 1,573.8	$ 980.9	$ 1,744.1	$ 364	$ 674.6	$ 6,236.1		$ 1,248.3	$ 795.2	$ 2,626.1	$ 388.5	$ 1,228.8	$ (337)	$ (29.9)	$ (28.9)	$ (165.7)	$ 6.5	$ (17.9)	$ 0.4	$ 0.3
Beginning Balance, Shares at Dec. 31, 2012	506,004,962						506,000,000
Issuance of Common Stock, Value	$ 83.2						$ 13.7						69.5
Issuance of Common Stock, Shares	2,109,002						2,100,000
Capital Contributions from Parent				0
Common Stock Dividends	$ (954.3)																		(950.5)	[1]
Common Stock Dividends		(285)	(72.5)	(375)	(71.2)	(125)															(285)	(72.5)	(375)	(71.2)	(125)
Common Stock Dividends						(3.8)																										(3.8)	(3.8)
Stockholders' Equity, Other	13.2												12.7																			0.5
Net Income (Loss)																			1,480.5						149.8
Net Income (Loss) Attributable to Noncontrolling Interests	3.7					4																										3.7	4
Net Income (Loss)	1,484.2	193.2	177.5	410	97.8	153.8															193.2	177.5	410	97.8
Other Comprehensive Income (Loss)	216.6	32.8	13.4	77.6	(0.7)	9.4																				216.6	32.8	13.4	77.6	(0.7)	9.4
Pension and OPEB Adjustment Related to Mitchell Plant	5.2																									5.2
Deferred State Income Tax Rate Adjustment				(5)												(5)
Distribution of Cook Coal Terminal to Parent				(2.7)																			(22.3)						19.6
Distribution of OPCo Generation to Parent				(3,005.3)												(1,075.3)							(2,005.6)						75.6
Contribution of Amos Plant from Parent		235.8												235.8
Contribution of Mutual Energy SWEPCo, LLC from Parent						0
Ending Balance at Dec. 31, 2013	$ 16,085.6	3,229.4	1,922.2	1,625.3	942.1	2,055.9	$ 3,302.7	260.4	56.6	321.2	157.2	135.7	6,131.2	1,809.6	980.9	663.8	364	674.6	6,766.1		1,156.5	900.2	633.2	415.1	1,253.6	(115.2)	2.9	(15.5)	7.1	5.8	(8.5)	0.8	0.5
Ending Balance, Shares at Dec. 31, 2013	508,113,964						508,100,000
Common Stock, Dividends, Per Share, Declared	$ 2.03
Issuance of Common Stock, Value	$ 73.6						$ 10.6						63
Issuance of Common Stock, Shares	1,625,195						1,600,000
Capital Contributions from Parent				175												175
Common Stock Dividends	$ (997.6)																		(993.3)	[1]
Common Stock Dividends		(80)	(125)	(35)		(100)															(80)	(125)	(35)		(100)
Common Stock Dividends						(4.3)																										(4.3)	(4.3)
Stockholders' Equity, Other	12.8												9.2																			3.6
Net Income (Loss)																			1,633.8						140.4
Net Income (Loss) Attributable to Noncontrolling Interests	4.2					4.2																										4.2	4.2
Net Income (Loss)	1,638	215.4	155.6	216.4	86.9	144.6															215.4	155.6	216.4	86.9
Other Comprehensive Income (Loss)	12.1	2.1	1.2	(1.5)	(0.8)	1																				12.1	2.1	1.2	(1.5)	(0.8)	1
Contribution of Amos Plant from Parent		0
Contribution of Mutual Energy SWEPCo, LLC from Parent						0
Ending Balance at Dec. 31, 2014	$ 16,824.5	3,366.9	1,954	1,980.2	$ 1,028.2	2,097.2	$ 3,313.3	260.4	56.6	321.2	157.2	135.7	6,203.4	1,809.6	980.9	838.8	364	674.6	7,406.6		1,291.9	930.8	814.6	502	1,294	(103.1)	5	(14.3)	5.6	5	(7.5)	4.3	0.4
Ending Balance, Shares at Dec. 31, 2014	509,739,159				10,482,000		509,700,000
Common Stock, Dividends, Per Share, Declared	$ 2.15
Issuance of Common Stock, Value	$ 81.6						$ 10.7						70.9
Issuance of Common Stock, Shares	1,650,014						1,700,000
Capital Contributions from Parent				0
Common Stock Dividends	$ (1,059)																		(1,055.4)	[1]
Common Stock Dividends		(243.8)	(120)	(225)		(120)															(243.8)	(120)	(225)		(120)
Common Stock Dividends						(3.6)																										(3.6)	(3.6)
Stockholders' Equity, Other	29.5												22.2																			7.3
Net Income (Loss)																			2,047.1						192.3
Net Income (Loss) Attributable to Noncontrolling Interests	5.2					3.7																										5.2	3.7
Net Income (Loss)	2,052.3	340.6	204.8	232.7	$ 92.5	196															340.6		232.7	92.5
Other Comprehensive Income (Loss)	(30)	(7.8)	(2.4)	(1.3)	(0.8)	(1.9)																				(30)	(7.8)		(1.3)	(0.8)	(1.9)
Pension and OPEB Adjustment Related to Mitchell Plant	6																									6
Contribution of Amos Plant from Parent		19.1												19.1
Contribution of Mutual Energy SWEPCo, LLC from Parent						2												2
Ending 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
Ending Balance, Shares at Dec. 31, 2015	511,389,173				10,482,000		511,400,000
[1]	(a)Cash dividends declared per AEP common share were $2.15, $2.03 and $1.95 as of December 31, 2015, 2014 and 2013, respectively.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents		$ 176.4	$ 162.5
Other Temporary Investments		386.8	385.6
Accounts Receivable:
Customers		615.9	637.2
Accrued Unbilled Revenues		31.2	146.1
Pledged Accounts Receivable - AEP Credit		940.3	987.4
Miscellaneous		82.1	85.3
Allowance for Uncollectible Accounts		(29)	(20.8)
Total Accounts Receivable		1,640.5	1,835.2
Fuel		600.8	580.8
Materials and Supplies		738.6	735.8
Risk Management Assets		134.4	177.9
Regulatory Asset for Under-Recovered Fuel Costs		115.2	126.6
Margin Deposits		107.3	95.2
Assets from Discontinued Operations		0	103.3
Prepayments and Other Current Assets		172.4	275.2
TOTAL CURRENT ASSETS		4,072.4	4,478.1
Property, Plant and Equipment
Generation		25,559.8	25,727.5
Transmission		14,247.9	12,433.4
Distribution		18,046.9	17,156.6
Other Property, Plant and Equipment		3,722.9	5,073.1
Construction Work in Progress		3,903.9	3,215.3
Total Property, Plant and Equipment		65,481.4	63,605.9
Accumulated Depreciation and Amortization		19,348.2	19,970.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,133.2	43,635.1	[1]
Other Noncurrent Assets
Regulatory Assets		5,140.3	4,263.7
Securitized Assets		1,749.9	2,072.4
Spent Nuclear Fuel and Decommissioning Trusts		2,106.4	2,095.7
Goodwill		52.5	52.5
Long-term Risk Management Assets		321.8	294.2
Assets from Discontinued Operations		0	521.6
Deferred Charges and Other Noncurrent Assets		2,106.6	2,131.3
TOTAL OTHER NONCURRENT ASSETS		11,477.5	11,431.4
TOTAL ASSETS		61,683.1	59,544.6
Current Liabilities
Accounts Payable		1,418	1,258.2
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[2]	675	744
Other Short-term Debt		125	602
Total Short-term Debt		800	1,346
Long-term Debt Due Within One Year		1,831.8	2,500.4
Long-term Debt Due Within One Year - Affiliated		0	0
Risk Management Liabilities		87.1	91.6
Customer Deposits		346.6	323.9
Accrued Taxes		979.1	863.5
Accrued Interest		226.9	238.3
Obligations Under Capital Leases		96.2	111.4
Regulatory Liability for Over-Recovered Fuel Costs		113.9	55.2
Liabilities from Discontinued Operations		0	84.8
Other Current Liabilities		1,305.1	1,204.7
TOTAL CURRENT LIABILITIES		7,108.5	7,966.6
Noncurrent Liabilities
Long-term Debt		17,740.9	16,012
Long-term Debt - Affiliated		0	0
Long-term Risk Management Liabilities		179.1	130.9
Deferred Income Taxes		11,733.2	10,892.2
Regulatory Liabilities and Deferred Investment Tax Credits		3,736.1	3,892.4
Asset Retirement Obligations		1,806.5	1,950.7
Employee Benefits and Pension Obligations		583.3	629.5
Obligations Under Capital Leases		247.3	440.4
Liabilities from Discontinued Operations		0	350
Deferred Credits and Other Noncurrent Liabilities		890.6	895.8
TOTAL NONCURRENT LIABILITIES		36,669.7	34,753.5
TOTAL LIABILITIES		$ 43,778.2	$ 42,720.1
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 3,324	$ 3,313.3
Paid-in Capital		6,296.5	6,203.4
Retained Earnings		8,398.3	7,406.6
Accumulated Other Comprehensive Income (Loss)		(127.1)	(103.1)
TOTAL COMMON SHAREHOLDER'S EQUITY		17,891.7	16,820.2
Noncontrolling Interests		13.2	4.3
TOTAL EQUITY		17,904.9	16,824.5
TOTAL LIABILITIES AND EQUITY		61,683.1	59,544.6
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.8	2.6
Restricted Cash for Securitized Funding		14.8	15.6
Advances to Affiliates		25.6	48.5
Accounts Receivable:
Customers		120.9	114.7
Affiliated Companies		51.2	67.3
Accrued Unbilled Revenues		17.9	58
Miscellaneous		2.2	2
Allowance for Uncollectible Accounts		(4.3)	(2.4)
Total Accounts Receivable		187.9	239.6
Fuel		119.3	113.4
Materials and Supplies		127	131.3
Risk Management Assets		14.7	23.8
Risk Management Assets - Affiliated		0.9	0
Deferred Income Tax Benefits		0	24
Accrued Tax Benefits		30.6	0.4
Regulatory Asset for Under-Recovered Fuel Costs		86.9	66.1
Prepayments and Other Current Assets		17.4	13.2
TOTAL CURRENT ASSETS		627.9	678.5
Property, Plant and Equipment
Generation		6,200.8	6,824
Transmission		2,408.1	2,228
Distribution		3,402.5	3,258.3
Other Property, Plant and Equipment		345.5	373.5
Construction Work in Progress		475.1	321.5
Total Property, Plant and Equipment		12,832	13,005.3
Accumulated Depreciation and Amortization		3,407.6	3,823.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,424.4	9,181.7
Other Noncurrent Assets
Regulatory Assets		1,154.2	857.9
Securitized Assets		328	350.2
Long-term Risk Management Assets		0.1	4.9
Deferred Charges and Other Noncurrent Assets		113.7	137.6
TOTAL OTHER NONCURRENT ASSETS		1,596	1,350.6
TOTAL ASSETS		11,648.3	11,210.8
Current Liabilities
Advances from Affiliates		181	0
Accounts Payable		196.5	166.8
Affiliated Companies		67.7	80.6
Short-term Debt:
Long-term Debt Due Within One Year		318	552.2
Long-term Debt Due Within One Year - Affiliated		0	86
Risk Management Liabilities		4.8	11
Customer Deposits		83.9	71.8
Accrued Taxes		79.5	109.5
Accrued Interest		40.6	52.2
Obligations Under Capital Leases		6.3	5.1
Other Current Liabilities		153.4	145
TOTAL CURRENT LIABILITIES		1,125.4	1,275.1
Noncurrent Liabilities
Long-term Debt		3,612.7	3,320.5
Long-term Risk Management Liabilities		0.1	2.1
Deferred Income Taxes		2,527	2,288.8
Regulatory Liabilities and Deferred Investment Tax Credits		637.1	652.9
Asset Retirement Obligations		98.9	122.3
Employee Benefits and Pension Obligations		114.4	128
Obligations Under Capital Leases		39.1	14.4
Deferred Credits and Other Noncurrent Liabilities		57.7	54.2
TOTAL NONCURRENT LIABILITIES		7,047.9	6,568.8
TOTAL LIABILITIES		$ 8,173.3	$ 7,843.9
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 260.4	$ 260.4
Paid-in Capital		1,828.7	1,809.6
Retained Earnings		1,388.7	1,291.9
Accumulated Other Comprehensive Income (Loss)		(2.8)	5
TOTAL EQUITY		3,475	3,366.9
TOTAL LIABILITIES AND EQUITY		11,648.3	11,210.8
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.1	1
Advances to Affiliates		11.7	13.5
Accounts Receivable:
Customers		43.9	57
Affiliated Companies		68.7	72.6
Accrued Unbilled Revenues		0.1	0.5
Miscellaneous		2.6	1.6
Allowance for Uncollectible Accounts		(0.1)	(0.5)
Total Accounts Receivable		115.2	131.2
Fuel		46.5	54.6
Materials and Supplies		185.9	201.1
Risk Management Assets		10.6	22.3
Risk Management Assets - Affiliated		1.7	0
Accrued Tax Benefits		40.5	24.8
Regulatory Asset for Under-Recovered Fuel Costs		11.6	0.8
Prepayments and Other Current Assets		42.1	28
TOTAL CURRENT ASSETS		455.3	476.5
Property, Plant and Equipment
Generation		3,841.7	3,741.9
Transmission		1,406.9	1,358.4
Distribution		1,790.8	1,698.4
Other Property, Plant and Equipment		662.3	1,490.8
Construction Work in Progress		519.8	537.2
Total Property, Plant and Equipment		8,221.5	8,826.7
Accumulated Depreciation and Amortization		3,018	3,410.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,203.5	5,416.4
Other Noncurrent Assets
Regulatory Assets		804.3	536.2
Spent Nuclear Fuel and Decommissioning Trusts		2,106.4	2,095.7
Long-term Risk Management Assets		0	3.3
Deferred Charges and Other Noncurrent Assets		140.9	129.4
TOTAL OTHER NONCURRENT ASSETS		3,051.6	2,764.6
TOTAL ASSETS		8,710.4	8,657.5
Current Liabilities
Advances from Affiliates		294.3	142.5
Accounts Payable		201	168.3
Affiliated Companies		61.8	76
Short-term Debt:
Long-term Debt Due Within One Year		162.9	382.2
Risk Management Liabilities		6.3	5.2
Customer Deposits		35.7	35.2
Accrued Taxes		74.2	72.7
Accrued Interest		26.2	26.7
Obligations Under Capital Leases		32.8	42.1
Regulatory Liability for Over-Recovered Fuel Costs		0.3	7.1
Other Current Liabilities		142.1	150.6
TOTAL CURRENT LIABILITIES		1,037.3	1,101.5
Noncurrent Liabilities
Long-term Debt		1,837.1	1,637.4
Long-term Risk Management Liabilities		1.6	1.4
Deferred Income Taxes		1,361.5	1,264.2
Regulatory Liabilities and Deferred Investment Tax Credits		1,076.2	1,199.7
Asset Retirement Obligations		1,240.9	1,337.1
Obligations Under Capital Leases		30.2	61.1
Deferred Credits and Other Noncurrent Liabilities		119.4	162.2
TOTAL NONCURRENT LIABILITIES		5,636.7	5,602
TOTAL LIABILITIES		$ 6,674	$ 6,703.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 56.6	$ 56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,015.6	930.8
Accumulated Other Comprehensive Income (Loss)		(16.7)	(14.3)
TOTAL EQUITY		2,036.4	1,954
TOTAL LIABILITIES AND EQUITY		8,710.4	8,657.5
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.1	2.9
Restricted Cash for Securitized Funding		27.7	28.7
Advances to Affiliates		331.1	312.5
Accounts Receivable:
Customers		46.4	57.9
Affiliated Companies		64.3	79.8
Accrued Unbilled Revenues		1.4	35.8
Miscellaneous		0.4	0.9
Allowance for Uncollectible Accounts		(0.2)	(0.2)
Total Accounts Receivable		112.3	174.2
Notes Receivable Due Within One Year - Affiliated		0	86
Materials and Supplies		86.1	60.9
Risk Management Assets		0	7.2
Deferred Income Tax Benefits		0	49.3
Accrued Tax Benefits		1.8	6.1
Prepayments and Other Current Assets		11.1	9
TOTAL CURRENT ASSETS		573.2	736.8
Property, Plant and Equipment
Transmission		2,235.6	2,104.6
Distribution		4,287.7	4,087.6
Other Property, Plant and Equipment		408.2	390.8
Construction Work in Progress		171.9	218.7
Total Property, Plant and Equipment		7,103.4	6,801.7
Accumulated Depreciation and Amortization		2,048.7	2,038.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,054.7	4,763.6
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3	32.3
Regulatory Assets		1,113	1,318.9
Securitized Assets		85.9	110
Long-term Risk Management Assets		19.2	45.1
Deferred Charges and Other Noncurrent Assets		259.6	253.9
TOTAL OTHER NONCURRENT ASSETS		1,510	1,760.2
TOTAL ASSETS		7,137.9	7,260.6
Current Liabilities
Accounts Payable		156.4	145.3
Affiliated Companies		88.7	172.8
Short-term Debt:
Long-term Debt Due Within One Year		395.9	131.5
Risk Management Liabilities		3.6	1.9
Customer Deposits		65.4	53.9
Accrued Taxes		528.3	420.8
Accrued Interest		33	34.3
Obligations Under Capital Leases		3.9	3.6
Regulatory Liability for Over-Recovered Fuel Costs		27.6	46.3
Other Current Liabilities		154.3	179.1
TOTAL CURRENT LIABILITIES		1,425.6	1,139.6
Noncurrent Liabilities
Long-term Debt		1,761.8	2,155.3
Long-term Risk Management Liabilities		0	3
Deferred Income Taxes		1,383.2	1,405.6
Regulatory Liabilities and Deferred Investment Tax Credits		514.2	514.7
Employee Benefits and Pension Obligations		35.8	36.7
Obligations Under Capital Leases		9.3	11
Deferred Credits and Other Noncurrent Liabilities		30.7	25.5
TOTAL NONCURRENT LIABILITIES		3,725.7	4,140.8
TOTAL LIABILITIES		$ 5,151.3	$ 5,280.4
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 321.2	$ 321.2
Paid-in Capital		838.8	838.8
Retained Earnings		822.3	814.6
Accumulated Other Comprehensive Income (Loss)		4.3	5.6
TOTAL EQUITY		1,986.6	1,980.2
TOTAL LIABILITIES AND EQUITY		7,137.9	7,260.6
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.4	1.4
Advances to Affiliates		80.6	0
Accounts Receivable:
Customers		26	28.4
Affiliated Companies		20.8	22.1
Miscellaneous		3.3	6
Allowance for Uncollectible Accounts		(0.6)	(0.1)
Total Accounts Receivable		49.5	56.4
Fuel		17.6	16.4
Materials and Supplies		51.9	50.9
Risk Management Assets		0.6	0
Accrued Tax Benefits		37.3	24.4
Regulatory Asset for Under-Recovered Fuel Costs		0	35.7
Prepayments and Other Current Assets		6.5	6.5
TOTAL CURRENT ASSETS		245.4	191.7
Property, Plant and Equipment
Generation		1,302.6	1,264.7
Transmission		815.4	788.9
Distribution		2,206.7	2,080.2
Other Property, Plant and Equipment		405.7	421.6
Construction Work in Progress		315.3	204.8
Total Property, Plant and Equipment		5,045.7	4,760.2
Accumulated Depreciation and Amortization		1,352.5	1,319.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,693.2	3,440.6
Other Noncurrent Assets
Regulatory Assets		214.8	154.3
Employee Benefits and Pension Assets		10.6	19.3
Deferred Charges and Other Noncurrent Assets		6.4	3.3
TOTAL OTHER NONCURRENT ASSETS		231.8	176.9
TOTAL ASSETS		4,170.4	3,809.2
Current Liabilities
Advances from Affiliates		0	154.2
Accounts Payable		108.2	92.7
Affiliated Companies		51.5	51.7
Short-term Debt:
Long-term Debt Due Within One Year		275.4	0.4
Risk Management Liabilities		0.2	0.9
Customer Deposits		50.3	48.7
Accrued Taxes		23.6	20.9
Accrued Interest		15.1	12.7
Obligations Under Capital Leases		3.7	3.4
Regulatory Liability for Over-Recovered Fuel Costs		76.1	0
Other Current Liabilities		64.4	58.9
TOTAL CURRENT LIABILITIES		664.8	441.1
Noncurrent Liabilities
Long-term Debt		1,010.7	1,036.3
Deferred Income Taxes		971.8	898.4
Regulatory Liabilities and Deferred Investment Tax Credits		335.1	334.5
Asset Retirement Obligations		39.9	37
Employee Benefits and Pension Obligations		14.5	20.1
Obligations Under Capital Leases		10.9	10.9
Deferred Credits and Other Noncurrent Liabilities		13.7	13.6
TOTAL NONCURRENT LIABILITIES		2,385.7	2,339.9
TOTAL LIABILITIES		$ 3,050.5	$ 2,781
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 157.2	$ 157.2
Paid-in Capital		364	364
Retained Earnings		594.5	502
Accumulated Other Comprehensive Income (Loss)		4.2	5
TOTAL EQUITY		1,119.9	1,028.2
TOTAL LIABILITIES AND EQUITY		4,170.4	3,809.2
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		5.2	14.4
Advances to Affiliates		2	41
Accounts Receivable:
Customers		40.2	46.7
Affiliated Companies		22	37.1
Miscellaneous		27.1	25.6
Allowance for Uncollectible Accounts		(0.9)	(0.5)
Total Accounts Receivable		88.4	108.9
Fuel		142.1	117
Materials and Supplies		71.5	73.7
Risk Management Assets		0.8	0
Deferred Income Tax Benefits		0	9
Accrued Tax Benefits		0	15.4
Regulatory Asset for Under-Recovered Fuel Costs		4.1	24
Prepayments and Other Current Assets		21.2	25.8
TOTAL CURRENT ASSETS		335.3	429.2
Property, Plant and Equipment
Generation		3,943.5	3,864.5
Transmission		1,387.8	1,300.7
Distribution		1,957.3	1,894.6
Other Property, Plant and Equipment		883.5	878.8
Construction Work in Progress		751.3	472
Total Property, Plant and Equipment		8,923.4	8,410.6
Accumulated Depreciation and Amortization		2,602.3	2,503.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,321.1	5,907.3
Other Noncurrent Assets
Regulatory Assets		415.8	393.6
Deferred Charges and Other Noncurrent Assets		75.8	78.7
TOTAL OTHER NONCURRENT ASSETS		491.6	472.3
TOTAL ASSETS		7,148	6,808.8
Current Liabilities
Advances from Affiliates		58.3	0
Accounts Payable		150.4	175.1
Affiliated Companies		78.8	67.4
Short-term Debt:
Long-term Debt Due Within One Year		3.3	306.8
Risk Management Liabilities		3.1	1.1
Customer Deposits		61.4	59.9
Accrued Taxes		58.3	44
Accrued Interest		43	44.3
Obligations Under Capital Leases		21.9	17.6
Regulatory Liability for Over-Recovered Fuel Costs		8.4	0
Other Current Liabilities		110.7	104.5
TOTAL CURRENT LIABILITIES		589.2	820.7
Noncurrent Liabilities
Long-term Debt		2,270.2	1,825.6
Long-term Risk Management Liabilities		2.1	0
Deferred Income Taxes		1,399.8	1,351.1
Regulatory Liabilities and Deferred Investment Tax Credits		448.8	458.5
Asset Retirement Obligations		117.5	92
Employee Benefits and Pension Obligations		25.8	25.4
Obligations Under Capital Leases		75.6	91
Deferred Credits and Other Noncurrent Liabilities		49.3	47.3
TOTAL NONCURRENT LIABILITIES		4,389.1	3,890.9
TOTAL LIABILITIES		$ 4,978.3	$ 4,711.6
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 135.7	$ 135.7
Paid-in Capital		676.6	674.6
Retained Earnings		1,366.3	1,294
Accumulated Other Comprehensive Income (Loss)		(9.4)	(7.5)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,169.2	2,096.8
Noncontrolling Interests		0.5	0.4
TOTAL EQUITY		2,169.7	2,097.2
TOTAL LIABILITIES AND EQUITY		$ 7,148	$ 6,808.8
[1]	Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents	$ 176.4	$ 162.5
Other Temporary Investments	386.8	385.6
Fuel	600.8	580.8
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	3,722.9	5,073.1
Accumulated Depreciation and Amortization	19,348.2	19,970.8
Current Liabilities
Long-term Debt Due Within One Year	1,831.8	2,500.4
Noncurrent Liabilities
Long-term Debt	$ 17,740.9	$ 16,012
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	511,389,173	509,739,159
Treasury Stock, Shares	20,336,592	20,336,592
Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 45.9	$ 45.4
Noncurrent Liabilities
Long-term Debt	139.4	184.5
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	2.8	2.6
Fuel	119.3	113.4
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	345.5	373.5
Accumulated Depreciation and Amortization	3,407.6	3,823.6
Current Liabilities
Long-term Debt Due Within One Year	318	552.2
Noncurrent Liabilities
Long-term Debt	$ 3,612.7	$ 3,320.5
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]
Common Stock, No Par Value
Current Assets
Cash and Cash Equivalents	$ 1.1	$ 1
Fuel	46.5	54.6
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	662.3	1,490.8
Accumulated Depreciation and Amortization	3,018	3,410.3
Current Liabilities
Long-term Debt Due Within One Year	162.9	382.2
Noncurrent Liabilities
Long-term Debt	$ 1,837.1	$ 1,637.4
Equity
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	$ 84.6	$ 85.7
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.1	2.9
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	408.2	390.8
Accumulated Depreciation and Amortization	2,048.7	2,038.1
Current Liabilities
Long-term Debt Due Within One Year	395.9	131.5
Noncurrent Liabilities
Long-term Debt	$ 1,761.8	$ 2,155.3
Equity
Common Stock, Par Value Per Share
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	$ 1.4	$ 1.4
Fuel	17.6	16.4
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	405.7	421.6
Accumulated Depreciation and Amortization	1,352.5	1,319.6
Current Liabilities
Long-term Debt Due Within One Year	275.4	0.4
Noncurrent Liabilities
Long-term Debt	$ 1,010.7	$ 1,036.3
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	$ 5.2	$ 14.4
Fuel	142.1	117
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	883.5	878.8
Accumulated Depreciation and Amortization	2,602.3	2,503.3
Current Liabilities
Long-term Debt Due Within One Year	3.3	306.8
Noncurrent Liabilities
Long-term Debt	$ 2,270.2	$ 1,825.6
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	$ 3.7	$ 12.7
Fuel	40.4	38.9
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	297.7	288.2
Accumulated Depreciation and Amortization	157.3	143
Subsidiaries [Member]
Current Assets
Other Temporary Investments	376.6	371
Current Liabilities
Long-term Debt Due Within One Year	410.4	430.5
Noncurrent Liabilities
Long-term Debt	$ 1,971.4	$ 2,241.1

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activites
Net Income (Loss)	$ 2,052.3	$ 1,638	$ 1,484.2
Income from Discontinued Operations, Net of Tax	283.7	47.5	10.3
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	1,768.6	1,590.5	1,473.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	2,009.7	1,897.6	1,712.5
Deferred Income Taxes	808.2	868.8	711.2
Asset Impairments and Other Related Charges	0	0	226.4
Carrying Costs Income	(23.5)	(33.2)	(30.2)
Allowance for Equity Funds Used During Construction	(131.9)	(102.9)	(72.7)
Mark-to-Market of Risk Management Contracts	52.5	(53.1)	38.5
Amortization of Nuclear Fuel	145	144.2	130.6
Pension and Postemployment Benefit Reserves	33.2	77.2	167.7
Pension Contributions to Qualified Plan Trust	(91.8)	(70.3)	0
Property Taxes	(52.4)	(41.8)	(35.4)
Fuel Over/Under-Recovery, Net	137.8	(35.5)	62
Deferral of Ohio Capacity Costs, Net	65.5	(113.5)	(214.4)
Change in Other Noncurrent Assets	(105.7)	35.6	(196.8)
Change in Other Noncurrent Liabilities	(89)	256.1	(152.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	200.2	(60.3)	22.9
Fuel, Materials and Supplies	(38.6)	100.8	119.2
Accounts Payable	16.5	(74.9)	94.1
Accrued Taxes, Net	120.2	0.4	86.2
Other Current Assets	(26.7)	(20.6)	15.4
Other Current Liabilities	(49.1)	237.3	(62.6)
Net Cash Flows from (Used for) Operating Activities	4,748.7	4,602.4	4,096.2
Investing Activities
Construction Expenditures	(4,508)	(4,130)	(3,616.4)
Change in Other Temporary Investments, Net	9.6	(31.1)	(11.2)
Purchases of Investment Securities	(2,282.7)	(1,088)	(927.4)
Sales of Investment Securities	2,218.4	1,031.8	858.4
Acquisitions of Nuclear Fuel	(92)	(116.2)	(153.7)
Acquisitions of Assets	(5.3)	(64.8)	(32)
Insurance Proceeds Related to Cook Plant Fire	0	0	72
Other Investing Activities	96	(7.6)	(7.5)
Net Cash Flows from (Used for) Investing Activities	(4,564)	(4,405.9)	(3,817.8)
Financing Activities
Issuance of Common Stock, Net	81.6	73.6	83.2
Issuance of Long-term Debt	3,436.6	2,067	3,206.6
Change in Short-term Debt, Net	(546)	589	(221)
Retirement of Long-term Debt	(2,397.9)	(1,777.4)	(2,595.4)
Make Whole Premium on Extinguishment of Long-term Debt	(92.7)	0	0
Proceeds from Nuclear Fuel Sale/Leaseback	0	0	110.2
Principal Payments for Capital Lease Obligations	(99)	(111.2)	(73.2)
Dividends Paid on Common Stock	(1,059)	(997.6)	(954.3)
Other Financing Activities	14.7	5.7	5.2
Net Cash Flows from (Used for) Financing Activities	(661.7)	(150.9)	(438.7)
Cash Provided by (Used in) Operating Activities, Discontinued Operations	69.8	11.1	9.5
Cash Provided by (Used in) Investing Activities, Discontinued Operations	548.8	(0.1)	(0.4)
Cash Provided by (Used in) Financing Activities, Discontinued Operations	(127.7)	(11.6)	(10)
Net Increase (Decrease) in Cash and Cash Equivalents	13.9	45	(161.2)
Cash and Cash Equivalents at Beginning of Period	162.5	117.5	278.7
Cash and Cash Equivalents at End of Period	176.4	162.5	117.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	857.2	838.5	882.1
Net Cash Paid (Received) for Income Taxes	120.2	117.3	(54.8)
Noncash Acquisitions Under Capital Leases	150.2	135.1	181.6
Construction Expenditures Included in Current Liabilities as of December 31,	741.4	559.3	492.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	37.9	44.5	0
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.2	3.4	4.4
Appalachian Power Co [Member]
Operating Activites
Net Income (Loss)	340.6	215.4	193.2
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	388.8	400.9	342.6
Deferred Income Taxes	227.5	144.7	75.7
Asset Impairments and Other Related Charges	0	0	39.3
Carrying Costs Income	(1.2)	(3)	(8.1)
Allowance for Equity Funds Used During Construction	(13.8)	(7.1)	(2.3)
Mark-to-Market of Risk Management Contracts	4.8	3.3	12.3
Pension Contributions to Qualified Plan Trust	(10)	(9)	0
Fuel Over/Under-Recovery, Net	(19.4)	(119.6)	59.2
Change in Other Noncurrent Assets	(56.9)	(14.9)	(1.4)
Change in Other Noncurrent Liabilities	(34.4)	51.8	20.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	51.7	68.6	12.5
Fuel, Materials and Supplies	(10.9)	76	28
Accounts Payable	0.3	(62.8)	(31.9)
Accrued Taxes, Net	(60.2)	(5.4)	81.2
Other Current Assets	(4.2)	(1)	5.6
Other Current Liabilities	(10.3)	23.8	(11.7)
Net Cash Flows from (Used for) Operating Activities	792.4	761.7	814.4
Investing Activities
Construction Expenditures	(636.2)	(497.4)	(381)
Change in Advances to Affiliates, Net	22.9	44	(69.5)
Other Investing Activities	13.9	(5.5)	(1.2)
Net Cash Flows from (Used for) Investing Activities	(599.4)	(458.9)	(451.7)
Financing Activities
Issuance of Long-term Debt	726.3	394.2	444.4
Change in Advances from Affiliates, Net	181	0	(174)
Retirement of Long-term Debt	(672.6)	(612.7)	(345)
Retirement of Long-term Debt - Affiliated	(86)	0	0
Make Whole Premium on Extinguishment of Long-term Debt	(92.7)	0	0
Principal Payments for Capital Lease Obligations	(5.5)	(5.6)	(5.5)
Dividends Paid on Common Stock	(243.8)	(80)	(285)
Other Financing Activities	0.5	1.2	1.5
Net Cash Flows from (Used for) Financing Activities	(192.8)	(302.9)	(363.6)
Net Increase (Decrease) in Cash and Cash Equivalents	0.2	(0.1)	(0.9)
Cash and Cash Equivalents at Beginning of Period	2.6	2.7	3.6
Cash and Cash Equivalents at End of Period	2.8	2.6	2.7
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	196.7	196.7	184.6
Net Cash Paid (Received) for Income Taxes	30.4	15.9	(27.8)
Noncash Acquisitions Under Capital Leases	31.8	4.9	4.4
Construction Expenditures Included in Current Liabilities as of December 31,	90.4	72	50.8
Noncash Contribution of Amos Plant from Parent	19.1	0	235.8
Indiana Michigan Power Co [Member]
Operating Activites
Net Income (Loss)	204.8	155.6	177.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	198.4	200.2	177.7
Deferred Income Taxes	94.2	70.2	129.1
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	11.2	20	(31.3)
Allowance for Equity Funds Used During Construction	(11.6)	(18.9)	(19.9)
Mark-to-Market of Risk Management Contracts	14.6	(6.1)	12.5
Amortization of Nuclear Fuel	145	144.2	130.6
Pension Contributions to Qualified Plan Trust	(14.6)	(8.9)	0
Fuel Over/Under-Recovery, Net	(17.7)	7.8	3.3
Change in Other Noncurrent Assets	(19.9)	(74.5)	(59.3)
Change in Other Noncurrent Liabilities	13.8	93.7	39.4
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	16	32.3	1.5
Fuel, Materials and Supplies	11.7	7.8	(8.8)
Accounts Payable	3.7	(20.4)	(11.2)
Accrued Taxes, Net	(14.3)	24.8	(23.9)
Other Current Assets	(4.8)	10.6	21.3
Other Current Liabilities	(7)	6.9	0.5
Net Cash Flows from (Used for) Operating Activities	623.5	645.3	539
Investing Activities
Construction Expenditures	(459.8)	(484.7)	(508.9)
Change in Advances to Affiliates, Net	1.8	42.4	61.1
Purchases of Investment Securities	(2,272)	(1,086.4)	(910)
Sales of Investment Securities	2,218.4	1,031.8	858.4
Acquisitions of Nuclear Fuel	(92)	(116.2)	(153.7)
Insurance Proceeds Related to Cook Plant Fire	0	0	72
Other Investing Activities	9.4	10.4	32.7
Net Cash Flows from (Used for) Investing Activities	(594.2)	(602.7)	(548.4)
Financing Activities
Issuance of Long-term Debt	310.7	205.6	348.9
Change in Advances from Affiliates, Net	151.8	142.5	0
Retirement of Long-term Debt	(332.1)	(218.5)	(370.3)
Proceeds from Nuclear Fuel Sale/Leaseback	0	0	110.2
Principal Payments for Capital Lease Obligations	(40.2)	(48.1)	(8.1)
Dividends Paid on Common Stock	(120)	(125)	(72.5)
Other Financing Activities	0.6	0.6	0.9
Net Cash Flows from (Used for) Financing Activities	(29.2)	(42.9)	9.1
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	(0.3)	(0.3)
Cash and Cash Equivalents at Beginning of Period	1	1.3	1.6
Cash and Cash Equivalents at End of Period	1.1	1	1.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	84.5	81.6	90.1
Net Cash Paid (Received) for Income Taxes	21.2	(10.2)	(31.3)
Noncash Acquisitions Under Capital Leases	3	16.4	114.1
Construction Expenditures Included in Current Liabilities as of December 31,	95.8	66.1	85.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	37.9	44.5	0
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	2.2	3.4	4.4
Ohio Power Co [Member]
Operating Activites
Net Income (Loss)	232.7	216.4	410
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	217.5	213.7	382.6
Amortization of Generation Deferrals	169.1	110.9	0
Deferred Income Taxes	37.6	74.4	134.5
Asset Impairments and Other Related Charges	0	0	154.3
Carrying Costs Income	(11.8)	(26.5)	(16.3)
Amortization (Deferral) of Storm Costs	0	0	(1.8)
Allowance for Equity Funds Used During Construction	(8.8)	(6.9)	(5)
Mark-to-Market of Risk Management Contracts	31.7	(44.5)	17.6
Pension Contributions to Qualified Plan Trust	(7.7)	(6.5)	0
Property Taxes	(24.7)	(4.6)	(11.8)
Fuel Over/Under-Recovery, Net	(18.7)	62.1	36.2
Deferral of Ohio Capacity Costs, Net	(30.7)	(157)	(214.4)
Change in Regulatory Assets	86.2	115.7	(14.4)
Change in Other Noncurrent Assets	(52.9)	(41.4)	42.5
Change in Other Noncurrent Liabilities	27.9	97.1	(49.3)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	61.9	(29.8)	86.6
Fuel, Materials and Supplies	(25.2)	(7.2)	80.3
Accounts Payable	(64.3)	(30.3)	(2.9)
Customer Deposits	11.5	4.8	(0.8)
Accrued Taxes, Net	111.8	(7.2)	23.8
Other Current Assets	(2.8)	1.5	7.8
Other Current Liabilities	(9.1)	22.9	(59.5)
Net Cash Flows from (Used for) Operating Activities	731.2	557.6	1,000
Investing Activities
Construction Expenditures	(453.3)	(453.5)	(640.1)
Change in Restricted Cash for Securitized Funding	1	(9.3)	(19.4)
Change in Advances to Affiliates, Net	(18.6)	26.6	4.3
Acquisitions of Assets	(0.6)	(3.5)	(4.1)
Proceeds from Sales of Assets	3.3	1.2	63
Proceeds from Notes Receivable - Affiliated	86	178.6	0
Other Investing Activities	10.4	4.8	2.4
Net Cash Flows from (Used for) Investing Activities	(371.8)	(255.1)	(593.9)
Financing Activities
Capital Contributions from Parent	0	175	0
Issuance of Long-term Debt	0	0	1,378.3
Issuance of Long-term Debt - Affiliated	0	0	200
Change in Advances from Affiliates, Net	0	0	1.2
Retirement of Long-term Debt	(131.5)	(438.6)	(1,196)
Retirement of Long-term Debt - Affiliated	0	0	(400)
Principal Payments for Capital Lease Obligations	(3.9)	(5.1)	(17.2)
Dividends Paid on Common Stock	(225)	(35)	(375)
Other Financing Activities	1.2	1.1	2
Net Cash Flows from (Used for) Financing Activities	(359.2)	(302.6)	(406.7)
Net Increase (Decrease) in Cash and Cash Equivalents	0.2	(0.1)	(0.6)
Cash and Cash Equivalents at Beginning of Period	2.9	3	3.6
Cash and Cash Equivalents at End of Period	3.1	2.9	3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	121.6	132.4	195.7
Net Cash Paid (Received) for Income Taxes	26.1	44	93.3
Noncash Acquisitions Under Capital Leases	2.7	4.8	7.7
Government Grants Included in Accounts Receivable as of December 31,	0	0	0.3
Construction Expenditures Included in Current Liabilities as of December 31,	34.3	43.4	92.3
Noncash Distribution of Cook Coal Terminal to Parent	0	0	(22.3)
Noncash Distribution of OPCo Generation to Parent	0	0	(3,080.9)
Public Service Co Of Oklahoma [Member]
Operating Activites
Net Income (Loss)	92.5	86.9	97.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	117.5	101	95.7
Deferred Income Taxes	58.3	74.7	53.8
Carrying Costs Income	0	0	(0.3)
Allowance for Equity Funds Used During Construction	(8.8)	(3.1)	(4.2)
Mark-to-Market of Risk Management Contracts	(1.4)	1.9	(6.4)
Pension Contributions to Qualified Plan Trust	(5.8)	(4.4)	0
Fuel Over/Under-Recovery, Net	111.8	(32.4)	(12.6)
Change in Regulatory Assets	(14.3)	16.7	(10.5)
Change in Other Noncurrent Assets	(25.7)	(22.6)	(6.6)
Change in Other Noncurrent Liabilities	5	(3.8)	(14.6)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	6.9	8.9	(4.4)
Fuel, Materials and Supplies	(2.2)	0.6	6.4
Accounts Payable	6.4	(26.3)	37.2
Accrued Taxes, Net	(10.2)	(5.6)	0.3
Other Current Assets	(1)	(0.8)	1.4
Other Current Liabilities	10.2	17.8	5.9
Net Cash Flows from (Used for) Operating Activities	339.2	209.5	238.9
Investing Activities
Construction Expenditures	(359.1)	(367.5)	(259.4)
Change in Advances to Affiliates, Net	(80.6)	0	10.6
Other Investing Activities	9.2	2.8	(2.1)
Net Cash Flows from (Used for) Investing Activities	(430.5)	(364.7)	(250.9)
Financing Activities
Issuance of Long-term Debt	248.8	75	49.7
Change in Advances from Affiliates, Net	(154.2)	117.5	36.7
Retirement of Long-term Debt	(0.4)	(34.1)	(0.4)
Principal Payments for Capital Lease Obligations	(3.6)	(3.7)	(3.5)
Dividends Paid on Common Stock	0	0	(71.2)
Other Financing Activities	0.7	0.6	0.6
Net Cash Flows from (Used for) Financing Activities	91.3	155.3	11.9
Net Increase (Decrease) in Cash and Cash Equivalents	0	0.1	(0.1)
Cash and Cash Equivalents at Beginning of Period	1.4	1.3	1.4
Cash and Cash Equivalents at End of Period	1.4	1.4	1.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	54.8	52.8	51.4
Net Cash Paid (Received) for Income Taxes	7.9	(21.2)	8.7
Noncash Acquisitions Under Capital Leases	3.6	2.3	5.8
Construction Expenditures Included in Current Liabilities as of December 31,	47.4	38.6	63.6
Southwestern Electric Power Co [Member]
Operating Activites
Net Income (Loss)	196	144.6	153.8
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	192	185.1	179.2
Deferred Income Taxes	41.9	239.4	81.9
Allowance for Equity Funds Used During Construction	(26.4)	(11.9)	(7.4)
Mark-to-Market of Risk Management Contracts	3.4	2.1	(1.5)
Pension Contributions to Qualified Plan Trust	(8.1)	(3.8)	0
Fuel Over/Under-Recovery, Net	28.3	(13.4)	(18.9)
Change in Regulatory Liabilities	(21.4)	(24.6)	(12.8)
Change in Other Noncurrent Assets	(1.6)	(3.6)	33.2
Change in Other Noncurrent Liabilities	15.4	25.1	0.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	20.5	25.5	(35.5)
Fuel, Materials and Supplies	(22.9)	6.3	6.6
Accounts Payable	(10.7)	4.4	12.8
Accrued Taxes, Net	29.7	(12.8)	25.3
Other Current Assets	1.1	(4.4)	(1.4)
Other Current Liabilities	(9.6)	21.2	1.7
Net Cash Flows from (Used for) Operating Activities	427.6	579.2	417.8
Investing Activities
Construction Expenditures	(540.6)	(511.4)	(411.5)
Change in Advances to Affiliates, Net	41	(41)	153.8
Other Investing Activities	5.9	5.1	(2.1)
Net Cash Flows from (Used for) Investing Activities	(493.7)	(547.3)	(259.8)
Financing Activities
Issuance of Long-term Debt	445.9	99.4	0
Credit Facility Borrowings	0	0	17.1
Change in Advances from Affiliates, Net	58.3	(9.2)	9.2
Retirement of Long-term Debt	(306.8)	(3.3)	(3.3)
Credit Facility Repayments	0	0	(19.7)
Principal Payments for Capital Lease Obligations	(17.7)	(18.3)	(18.1)
Dividends Paid on Common Stock	(120)	(100)	(125)
Dividends Paid on Common Stock	(3.6)	(4.3)	(3.8)
Other Financing Activities	0.8	1	0.8
Net Cash Flows from (Used for) Financing Activities	56.9	(34.7)	(142.8)
Net Increase (Decrease) in Cash and Cash Equivalents	(9.2)	(2.8)	15.2
Cash and Cash Equivalents at Beginning of Period	14.4	17.2	2
Cash and Cash Equivalents at End of Period	5.2	14.4	17.2
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	112.6	116.9	120.4
Net Cash Paid (Received) for Income Taxes	15.4	(152.2)	(35.4)
Noncash Acquisitions Under Capital Leases	7.4	4.1	9.4
Construction Expenditures Included in Current Liabilities as of December 31,	92.9	94.3	63.2
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent	(2)	0	0
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC	$ 2	$ 0	$ 0

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable
Appalachian Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable
Indiana Michigan Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable
Ohio Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable
Public Service Co Of Oklahoma [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable
Southwestern Electric Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Corporate Separation (Applies to AEP, APCo, I&M and OPCo) On December 31, 2013, as approved by the FERC and the PUCO, OPCo transferred its generation assets and related generation liabilities at net book value to AGR. In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers. Effective January 1, 2014, OPCo began purchasing power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers. In 2013, in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo transferred its ownership of Cook Coal Terminal to AEGCo and sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC). On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo and one-half of its interest (780 MW) in the Mitchell Plant to KPCo. APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.” However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements. As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer. Other Impacts of Corporate Separation The Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated. Effective January 1, 2014, the FERC approved: • A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Under the PCA, APCo, I&M and KPCo are individually responsible for planning their respective capacity obligations and there are no capacity equalization charges/credits under the PCA on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR is committed to use its capacity to help meet the PJM capacity obligations of member companies. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88 /MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. AEPRO’s assets and liabilities have been recorded as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on the balance sheet as of December 31, 2014. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented as well as amounts related to Assets from Discontinued Operations and Liabilities from Discontinued Operations as of December 31, 2014. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. 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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2015
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.
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 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. 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. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. As applicable, this standard may change the presentation of amounts in the income statements. Management adopted ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-03 in October 2015 and applied the new standard retrospectively for all periods presented. Prior to adoption, the Registrants included debt issuance costs in Deferred Charges and Other Noncurrent Assets on the balance sheets. The effect of the reclassification between assets and liabilities for each Registrant as of December 31, 2014 is disclosed in the table below. Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1 ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management adopted ASU 2015-05 prospectively, effective January 1, 2016, with no impact on results of operations, financial position or cash flows. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management does not expect the new standard to impact its results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it had no impact on the accounting of the Registrants’ contracts. Additionally, adoption had no impact on net income. Management adopted ASU 2015-13 upon its issuance date. ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU 2015-17) In November 2015, the FASB issued ASU 2015-17 simplifying the presentation of deferred income taxes on the balance sheets. Under the new standard, deferred tax assets and liabilities are classified as noncurrent on the balance sheets. The new accounting guidance is effective for annual periods beginning after December 15, 2016 with early adoption permitted. Management adopted ASU 2015-17 upon its issuance date and applied the new standard prospectively. As a result, the new standard impacted the December 31, 2015 presentation of deferred tax assets and liabilities on the balance sheet. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments should 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.

Comprehensive Income

Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Comprehensive Income	3 . COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Appalachian Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Indiana Michigan Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Ohio Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Public Service Co Of Oklahoma [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Southwestern Electric Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 . All amounts in the following tables are presented net of related income taxes. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the years ended December 31, 2015 , 2014 and 2013 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4 APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2 PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2015
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o
Ohio Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o
Public Service Co Of Oklahoma [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total combined revenue, annual base rates were authorized to be increased by $99 million ( $85 million related to APCo) based upon a 9.75% return on common equity. The order included a delayed billing of $25 million ( $22 million related to APCo) of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a weighted average cost of capital (WACC) rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed concurrent with the next ENEC change in rates. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million ( $38 million related to APCo) annually, (b) revised deprecation rates, including recovery of plants to be retired in the second quarter of 2015 and (c) the recovery of $89 million ( $77 million related to APCo) in previously recorded regulatory assets, which will predominantly be recovered over five years. In February 2016, APCo and WPCo filed a petition with the WVPSC to implement recovery of the delayed billing totaling $29 million ( $26 million related to APCo), which includes carrying charges through June 2016. Recovery of the $29 million was requested over two years, beginning July 2016, with the unpaid principal subject to carrying charges. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets and briefs related to this proceeding were filed by various parties. The Virginia SCC has no statutory deadline to issue its decision in this proceeding. As of December 31, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $10 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. Virginia Legislation Affecting Biennial Reviews In February 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 new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 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 February 2016, certain APCo industrial customers filed a petition with the Virginia SCC requesting the issuance of a declaratory order that finds the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, directs APCo to make biennial review filings beginning March 2016. In February 2016, APCo filed a motion to stay the Virginia SCC’s consideration of the petition due to a pending appeal at the Supreme Court of Virginia by industrial customers of a non-related utility regarding the constitutionality of the 2015 amendments. Oral arguments at the Virginia SCC are scheduled for March 2016. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of December 31, 2015, AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $433 million based upon interim rate increases received from 2009 through 2015. In November 2015, the PUCT ordered ETT to file a base rate case by February 2017. 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 that are reasonably possible of occurring. 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) Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M’s Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M’s request for revised depreciation rates. Revised depreciation rates were previously approved by the MPSC in 2014, along with a credit rider to reduce customer rates upon retirement of Tanners Creek Plant. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In 2015, the IURC granted I&M’s motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters (Applies to AEP) Plant Transfer Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC’s October 2013 order. In May 2015, the Attorney General filed an appeal with the Kentucky Court of Appeals of the April 2015 order. In December 2015, KPCo, the Attorney General and the KPSC filed a joint motion to dismiss the appeals filed with the Kentucky Court of Appeals and in February 2016, the joint motion to dismiss was granted. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the “2014 Kentucky Base Rate Case” discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a stipulation agreement between KPCo and certain intervenors was filed with the KPSC that recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflected KPCo’s ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. The proposed net increase of $45 million also included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment clause review. See “Kentucky Fuel Adjustment Clause Review” discussed above. In June 2015, the KPSC issued an order that approved a modified stipulation agreement. The order approved a net revenue increase of $45 million , as proposed in the stipulation agreement, and contained modifications that included (a) approval to recover $2 million of IGCC and certain carbon capture study costs, both over 25 years, (b) no deferral of certain PJM costs and (c) denial of the recovery of certain potential purchased power costs through a rider. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In September 2015, KGPCo filed a request with the TRA to increase base rates by $12 million annually based upon a proposed return on common equity of 10.66% . In December 2015, KGPCo withdrew its base rate case filing for administrative purposes and refiled its request with the TRA in January 2016. If KGPCo does not recover its costs, 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 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a WACC rate. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed an appeal filed by the IEU. In September 2015, the Supreme Court of Ohio denied a request for reconsideration filed by the IEU and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. A decision from the PUCO is pending. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. Oral arguments at the Supreme Court of Ohio were held in December 2015. A decision from the Supreme Court of Ohio is pending. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo’s July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of December 31, 2015 , OPCo’s net deferred capacity costs balance of $359 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. Through December 31, 2015 , OPCo has collected $222 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo’s $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. 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. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order 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 PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo’s and various intervenors’ requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2015, the Supreme Court of Ohio granted the PUCO’s motion to dismiss these intervenor appeals, without prejudice, since rehearing related to the PPA issues was still pending. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo’s OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. Hearings at the PUCO related to the PPA were concluded in November 2015. In December 2015, a non-unanimous stipulation agreement related to the PPA application was filed with the PUCO. The stipulation agreement is based upon a 10.38% return on common equity with the PPA Rider term extending through May 2024. The stipulation agreement included (a) a revised affiliate PPA between OPCo and AGR to be included in the PPA Rider, (b) OPCo’s OVEC contractual entitlement, (c) a potential additional customer credit to be included in the PPA Rider, (d) annual compliance reviews before the PUCO and (e) an agreement to retire, refuel or repower, to 100% natural gas, Conesville Plant, Units 5 and 6 and Cardinal Plant, Unit 1 by 2029 and 2030, respectively. Additionally, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. OPCo would own up to 50% of these solar and wind projects and would include cost recovery in the proposed PPA rider, subject to PUCO review and approval. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. Hearings related to this proposed stipulation agreement were held in January 2016. Management anticipates receiving an order from the PUCO in the first quarter of 2016. In January 2016, intervenors filed a complaint at the FERC related to the affiliate PPA. The complaint asserts that the proposed affiliate PPA between AGR and OPCo is reviewable by the FERC under its standards for affiliate transactions. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. In December 2013, corporate separation of OPCo’s generation assets was completed. In December 2015, the IEU withdrew its appeal. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the “June 2012 - May 2015 ESP Including Capacity Charge” section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In November 2015, the PUCO issued an order approving the stipulation agreement and OPCo’s request to recover its remaining $10 million of Ormet deferrals through the EDR. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of December 31, 2015 , PSO had incurred costs of $190 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of December 31, 2015 , the net book value of Northeastern Plant, Unit 4 was $93 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, some intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC were held in December 2015. In January 2016, PSO implemented an interim annual base rate increase of $75 million . These interim rates are subject to refund pending a final order from the OCC related to the initial $137 million request. An order from the OCC is anticipated in the second quarter of 2016. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. 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 May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo’s Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery o

Effects of Regulation

Effects of Regulation	12 Months Ended
	Dec. 31, 2015
Effects of Regulation	5 . EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.
Appalachian Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.
Indiana Michigan Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.
Ohio Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.
Public Service Co Of Oklahoma [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.
Southwestern Electric Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulated Generating Units Expected to be Retired During 2016 (Applies to AEP, PSO and SWEPCo) The following regulated generating units are probable of abandonment. Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheets as of December 31, 2015 and 2014. The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2015 . Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7 AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9 APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2 I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9 OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3 PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6 SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2015 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. As of December 31, 2015 , AEP’s maximum future payments for letters of credit issued under the revolving credit facilities were $23 million with maturities ranging from February 2016 to December 2016. In January 2016, the letter of credit maturing in February 2016 was replaced with a new letter of credit expiring in January 2017. 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 three uncommitted facilities totaling $225 million . As of December 31, 2015 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016 The Registrants have $477 million of variable rate Pollution Control Bonds supported by $482 million of bilateral letters of credit as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled. Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2015 , SWEPCo has collected approximately $65 million through a rider for final mine closure and reclamation costs, of which $15 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations 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. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2015 , 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. 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. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2015 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo, SWEPCo and other AEP subsidiaries received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. SWEPCo has also been named potentially liable at one site under state law. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. 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 December 31, 2015 , I&M’s accrual for all of these sites is $8 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. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $10 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2015 and 2014 , the total decommissioning trust fund balance was $1.8 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. This fee was terminated in May 2014. As of December 31, 2015 and 2014 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $13 million , $22 million and $31 million in 2015 , 2014 and 2013 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. The proceeds reduced costs for dry cask storage. As of December 31, 2015 , I&M has deferred $6 million in Prepayments and Other Current Assets and $21 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Incident Liability I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion . Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $49 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.5 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $13.1 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In 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 plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. 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 plaintiff’s claims. Several claims remain, 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 plaintiff 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 plaintiff’s motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. Management will continue to defend against the remaining claims. 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, the Lieutenant Governor of California filed a lawsuit 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 California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) 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 appellate court reversed the district court’s holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants’ previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs’ state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP’s petition for review of the personal jurisdiction issue shortly thereafter. The cases were remanded to the district court for further proceedings. There are four pending cases, of which three are class actions and one is a single plaintiff case. A tentative settlement has been reached in the three class actions. This settlement, once finalized, will be subject to court approval. Management will continue to defend the remaining case. Management is unable to determine the amount of potential additional loss that is reasonably possible of occurring. Wage and Hours Lawsuit (Applies to AEP and PSO) In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they were denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. In January 2016, the plaintiffs’ lead counsel filed a motion to withdraw from the case and the motion was denied by the court. Subsequently, a motion to dismiss without prejudice was filed on behalf of 35 named plaintiffs. In February 2016, PSO filed a motion for summary judgment. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . National Do Not Call Registry Lawsuit (Applies to AEP) In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. The court granted final approval of the settlement in September 2015 and terminated the case in November 2015. The settlement had an immaterial impact to AEP’s financial statements. 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. 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. Eleven of the family members are pursuing personal injury/illness 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, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management 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 rather than back to the Mason County, West Virginia Circuit Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Dispositions and Impairments

Dispositions and Impairments	12 Months Ended
	Dec. 31, 2015
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.
Appalachian Power Co [Member]
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.
Indiana Michigan Power Co [Member]
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.
Ohio Power Co [Member]
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.
Public Service Co Of Oklahoma [Member]
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.
Southwestern Electric Power Co [Member]
Dispositions and Impairments	DISPOSITIONS AND IMPAIRMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. DISPOSITIONS 2015 AEPRO (Corporate and Other) (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 and resulted in a net gain of $253 million that was recorded in Income from Discontinued Operations, Net of Tax, on the statement of income. AEP received net cash proceeds from the sale of $491 million , which were immediately available for use in AEP’s continuing operations. The cash proceeds of $539 million were recorded in Discontinued Investing Activities on the statement of cash flows. These proceeds were reduced by a make whole payment on the extinguishment of AEPRO long-term debt of $32 million , which was recorded in Discontinued Financing Activities, and transaction costs of $16 million , which were recorded in Discontinued Operating Activities, on the statement of cash flows. The nonaffiliated party acquired AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party assumed certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. Prior to the closing of the sale, AEP retired the debt obligations of AEPRO. AEP retained ownership of its captive barge fleet that delivers coal to the company’s regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. AEP signed a contract with the nonaffiliated party to dispatch and schedule its captive barge fleet for the company’s regulated coal-fueled power plant units. AEP also has a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. In the third quarter of 2015, AEPRO was determined to be discontinued operations and subsequently classified as held for sale. The assets and liabilities were classified as Assets from Discontinued Operations and Liabilities from Discontinued Operations, respectively, on AEP’s balance sheet as of December 31, 2014 and as shown in the following table: December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015, 2014 and 2013 as shown in the following table: Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 Muskingum River Plant (Generation & Marketing segment) (Applies to AEP) In August 2015, AGR sold its retired Muskingum River Plant site including its associated Asset Retirement Obligations (ARO) to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and ARO, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the statement of income. The cash paid was recorded in Operating Activities on the statements of cash flows. 2013 Conesville Coal Preparation Company (Transmission and Distribution Utilities segment) (Applies to AEP and OPCo) In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company. This sale did not have a significant impact on OPCo’s financial statements. IMPAIRMENTS 2013 Amos Plant, Unit 3 (Vertically Integrated Utilities segment) (Applies to AEP and APCo) In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the reduced price was approximately $39 million . As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income. No impairment was recorded for the West Virginia jurisdictional share as these amounts were approved for recovery in the 2014 West Virginia Base Rate Case. Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment) (Applies to AEP) In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project as disallowed by the KPSC. Muskingum River Plant, Unit 5 (Generation & Marketing segment) (Applies to AEP and OPCo) In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo had the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, management recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. The plant was retired in May 2015.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2015
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25
Appalachian Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25
Indiana Michigan Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25
Ohio Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25
Public Service Co Of Oklahoma [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25
Southwestern Electric Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded 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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2015 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below: Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2015 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2015 and 2014 The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Recognized on the Balance Sheets as of December 31, 2015 and 2014 Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5 Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4 Amounts Included in AOCI and Regulatory Assets as of December 31, 2015 and 2014 AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 ) APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 ) I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 ) OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 ) SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 ) Components of the change in amounts included in AOCI and Regulatory Assets by Registrant during the years ended December 31, 2015 and 2014 are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9 APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2 I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9 OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8 PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8 SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries as of December 31, 2015 and 2014 using the percentages in the table below: Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2014 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2015 and 2014 were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2016 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the years ended December 31, 2015 , 2014 and 2013 : AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 ) APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2015
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 manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Appalachian Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Indiana Michigan Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Ohio Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Public Service Co Of Oklahoma [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Southwestern Electric Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manage 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, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities are presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2015 , 2014 and 2013 and reportable segment balance sheet information as of December 31, 2015 and 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business starting in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

Derivatives and Hedging

Derivatives and Hedging	12 Months Ended
	Dec. 31, 2015
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp
Appalachian Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp
Indiana Michigan Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp
Ohio Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp
Southwestern Electric Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 as of December 31, 2015 and 2014 : Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ — 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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. For the December 31, 2015 and 2014 balance sheets, 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: December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of December 31, 2015 and 2014 : AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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. I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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. OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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. PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 for the years ended December 31, 2015 , 2014 and 2013 : Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. 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 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) during 2015 , 2014 , and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4 For 2015 , 2014 and 2013 , 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding power derivatives. During 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014, APCo and I&M applied cash flow hedging to outstanding power derivatives. During 2013 , APCo, I&M and OPCo applied cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. During 2013 , the Registrants applied cash flow hedging to outstanding heating oil and gasoline derivatives. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. 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 2015 , 2014 and 2013 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2013 , I&M applied 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 2015 , 2014 and 2013 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During 2015 , 2014 and 2013 , 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 as of December 31, 2015 and 2014 were: Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Comp

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of December 31, 2015 and 2014 are summarized in the following table: December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO. 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 its protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — As of December 31, 2015 and 2014 , AEP had no Other Temporary Investments with an unrealized loss position. As of December 31, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments as of December 31, 2015 and 2014 : December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 ) The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1 The adjusted cost of fixed income securities was $771 million and $903 million as of December 31, 2015 and 2014 , respectively. The adjusted cost of equity securities was $555 million and $524 million as of December 31, 2015 and 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2015 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . 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 December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2015 , 2014 and 2013 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2015 and 2014 : Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2015 and 2014 : 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	12 Months Ended
	Dec. 31, 2015
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not 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. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not 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. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not 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. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not 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. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not 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. Income Tax Expense The details of the Registrants’ income taxes before discontinued operations as reported are as follows: AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 % APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance (Applies to AEP) AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. A valuation allowance of $130 million and $56 million was recorded against AEP’s deferred tax asset balance as of December 31, 2015 and 2014, respectively. The valuation allowance reflects management’s assessment of the amount of its deferred tax assets that are more than likely not to be realized. The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income are materially impacted during the carryforward period. 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. 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 and foreign jurisdictions. These taxing authorities routinely examine their 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. Net Income Tax Operating Loss Carryforward In 2012 and 2011, AEP recognized federal net income tax operating losses of $366 million and $226 million , respectively, and in 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million , respectively. The losses for AEP, APCo and I&M were driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences. In 2012, SWEPCo recognized federal net income tax operating losses of $858 million which were driven primarily by bonus depreciation. As of December 31, 2013, AEP had $156 million of unrealized federal net operating loss carryforward tax benefits. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. AEP recognized deferred state and local income tax benefits in 2012 and 2011. AEP, APCo, OPCo, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2015 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035 As a result, APCo, OPCo, PSO and SWEPCo recognized deferred state and local income tax benefits in 2011, and/or 2012, and/or 2013, and/or 2014 and/or 2015. At the end of 2013, APCo, I&M and SWEPCo had $12 million , $13 million and $167 million , respectively, of unrealized federal net operating loss carryforward. Federal taxable income was sufficient enough in 2014 that these remaining federal net income tax operating loss tax benefits were realized in full. Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2015 and 2014, AEP had $59 million and $52 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2015, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2030 through 2035 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million , but did not result in the receipt of cash as of December 31, 2015. Due to the timing of the IRS audit cycle, receipt of cash is not expected within the next 12 months. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — — The following table shows balances for amounts accrued for the receipt of interest: December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — — The following table shows balances for amounts accrued for the payment of interest and penalties: December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4 Federal Tax Legislation The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013. Included in the 2012 Act was a one-year extension of the 50% bonus depreciation. The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2013. The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provisions did not materially impact net income, cash flows or financial condition.

Leases

Leases	12 Months Ended
	Dec. 31, 2015
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Appalachian Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Indiana Michigan Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Ohio Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Public Service Co Of Oklahoma [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Southwestern Electric Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 34 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Future minimum lease payments consisted of the following as of December 31, 2015 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6 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 December 31, 2015 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2015 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. 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 assignment is 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 $10 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2015 . These obligations are included in the future minimum lease payments schedule earlier in this note. 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 $9 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 2015, 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. See “AEPRO (Corporate and Other)” section of Note 7 . 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 2026. As of December 31, 2015, the maximum potential amount of future payments required under the guaranteed leases was $94 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2015, AEP’s boat and barge lease guarantee liability was $16 million . Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. These capital lease assets are included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $35 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2015 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1

Financing Activities

Financing Activities	12 Months Ended
	Dec. 31, 2015
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (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 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Appalachian Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, 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 December 31, 2015 and 2014 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 years ended December 31, 2015 and 2014 are described in the following tables: Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015 , 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 % Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 — Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1 Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Indiana Michigan Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, 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 December 31, 2015 and 2014 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 years ended December 31, 2015 and 2014 are described in the following tables: Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015 , 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 % Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 — Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1 Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Ohio Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, 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 December 31, 2015 and 2014 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 years ended December 31, 2015 and 2014 are described in the following tables: Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015 , 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 % Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 — Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1 Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Public Service Co Of Oklahoma [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, 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 December 31, 2015 and 2014 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 years ended December 31, 2015 and 2014 are described in the following tables: Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015 , 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 % Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 — Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1 Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Southwestern Electric Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity for the years ended December 31, 2015 , 2014 and 2013 : Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Long-term Debt The following details long-term debt outstanding as of December 31, 2015 and 2014 : Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). Long-term debt outstanding as of December 31, 2015 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5 In January 2016 and February 2016, I&M retired $14 million and $8 million , respectively, of Notes Payable related to DCC Fuel. In January 2016, APCo retired $75 million of variable rate Pollution Control Bonds due in 2016 and issued $75 million of variable rate Pollution Control Bonds due on demand. In January 2016, OPCo retired $23 million of Securitization Bonds. In January 2016, TCC retired $128 million of Securitization Bonds. In February 2016, APCo retired $11 million of Securitization Bonds. In February 2016, Transource Missouri drew $3 million on an existing $300 million variable rate credit facility due in 2018 . As of December 31, 2015 , trustees held, on behalf of AEP, $554 million of their reacquired Pollution Control Bonds. Of this total, $40 million and $345 million related to I&M and OPCo, respectively. Dividend Restrictions Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2015 , none of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions 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. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. As of December 31, 2015 , the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was $8.1 billion . As of December 31, 2015 , none of APCo’s retained earnings had restrictions related to the payment of dividends to Parent, while $92 million , $105 million and $354 million of I&M’s, PSO’s and SWEPCo’s retained earnings, respectively, had restrictions related to the payment of dividends to Parent. The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” As of December 31, 2015 , this restriction did not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. 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. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2015 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2015 was $788 million and the weighted average interest rate of commercial paper outstanding during 2015 was 0.46% . AEP’s outstanding short-term debt was as follows: December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, 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 December 31, 2015 and 2014 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 years ended December 31, 2015 and 2014 are described in the following tables: Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2015 , 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the year ended December 31, 2015 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 % Interest expense related to short-term borrowing activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 — Interest income related to short-term lending activities with the Utility Money Pool and the Nonutility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1 Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, in SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $4 thousand of interest income for the year ended December 31, 2015 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Sale of 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. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9 December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Sale of Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2015 and 2014 was as follows: December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Stock-based Compensation	STOCK-BASED COMPENSATION The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries. AEP’s long-term incentive plan available for eligible employees and directors, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2015 , 9,964,153 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. To the extent the issuance of a share that is subject to an outstanding award under the Prior Plan, the issuance of that share will take place under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Stock Options AEP did not grant stock options in 2015 , 2014 or 2013 . AEP did have outstanding stock options from grants in earlier periods that were exercised in 2013. As of December 31, 2015 , AEP has no outstanding stock options. AEP recorded compensation cost for stock options over the vesting period based on the fair value on the grant date. The 2015 LTIP specifies a maximum contractual term of 10 years for stock options. The total intrinsic value of options exercised is as follows: Years Ended December 31, Stock Options 2015 2014 2013 (in millions) Intrinsic Value of Options Exercised (a) $ — $ — $ 3.1 (a) Intrinsic value is calculated as market price at exercise dates less the option exercise price. A summary of AEP stock option transactions during the years ended December 31, 2015 , 2014 and 2013 is as follows: 2015 2014 2013 Options Weighted Average Exercise Price Options Weighted Average Exercise Price Options Weighted Average Exercise Price (in thousands) (in thousands) (in thousands) Outstanding as of January 1, — NA — NA 188.5 $ 30.17 Granted — NA — NA — NA Exercised/Converted — NA — NA (187.5 ) 30.18 Forfeited/Expired — NA — NA (1.0 ) 27.95 Outstanding as of December 31, — NA — NA — NA Options Exercisable as of December 31, — NA — NA — NA NA Not applicable. AEP includes the proceeds received from exercised stock options in common stock and paid-in capital. Performance Units Pursuant to the 2015 LTIP, AEP’s performance units are paid out in cash rather than AEP shares. For that reason, AEP’s performance units no longer reduce the aggregate share authorization. AEP’s performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. The number of performance units held at the end of the three year performance period is multiplied by the performance score to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee. Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, their performance units are mandatorily deferred as AEP career shares. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over a three-year vesting period. The liability for both the performance units and AEP career shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value. The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP career shares for the years ended December 31, 2015 , 2014 and 2013 as follows: Years Ended December 31, Performance Units 2015 2014 2013 Awarded Units (in thousands) 575.0 16.9 1,284.2 Weighted Average Unit Fair Value at Grant Date $ 59.19 $ 49.73 $ 46.23 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2015 2014 2013 Awarded Units (in thousands) 103.6 98.9 100.9 Weighted Average Fair Value at Grant Date $ 54.35 $ 53.35 $ 45.42 Vesting Period (in years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s employment ends. Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to the Standard and Poor’s 500 Electric Utilities Index and (b) three -year cumulative earnings per share measured relative to a target approved by AEP’s Board of Directors. The certified performance scores and units earned for the three-year periods ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Performance Units 2015 2014 2013 Certified Performance Score 176.3 % 147.8 % 118.8 % Performance Units Earned 1,202,107 889,697 749,219 Performance Units Mandatorily Deferred as AEP Career Shares 41,707 40,831 72,883 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 54,074 39,526 39,691 Performance Units to be Paid in Cash 1,106,326 809,340 636,645 The cash payouts for the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Performance Units and AEP Career Shares 2015 2014 2013 (in millions) Cash Payouts for Performance Units $ 48.1 $ 29.3 $ 43.9 Cash Payouts for AEP Career Share Distributions 3.0 4.3 3.7 Restricted Stock Units The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends. Additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into a share of AEP common stock upon vesting, except for AEP’s officers subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash. In 2014, there were no RSUs granted to Section 16 officers due to a change that deferred granting these and other awards until February 2015. For RSUs paid in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date. In 2010, the HR Committee granted a total of 165,520 RSUs to four Chief Executive Officer succession candidates as a retention incentive for these candidates. These grants vested in three approximately equal installments on August 3, 2013, August 3, 2014 and August 3, 2015. The HR Committee awarded RSUs, including additional units awarded as dividends, for the years ended December 31, 2015 , 2014 and 2013 as follows: Years Ended December 31, Restricted Stock Units 2015 2014 2013 Awarded Units (in thousands) 397.5 64.1 644.4 Weighted Average Grant Date Fair Value $ 58.56 $ 50.36 $ 46.24 The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Restricted Stock Units 2015 2014 2013 (in millions) Fair Value of Restricted Stock Units Vested $ 18.3 $ 18.7 $ 15.3 Intrinsic Value of Restricted Stock Units Vested (a) 24.2 24.9 20.4 (a) Intrinsic value is calculated as market price at exercise date. A summary of the status of AEP’s nonvested RSUs as of December 31, 2015 and changes during the year ended December 31, 2015 are as follows: Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2015 783.0 $ 44.59 Granted 397.5 58.56 Vested (425.4 ) 42.94 Forfeited (33.8 ) 51.07 Nonvested as of December 31, 2015 721.3 52.48 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2015 was $41 million and the weighted average remaining contractual life was 1.9 years . Other Stock-Based Plans AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date. The cash payouts for stock unit distributions for the years ended December 31, 2015 , 2014 and 2013 were $1 million , $5 million and $2 million , respectively. The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2015 , 2014 and 2013 as follows: Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2015 2014 2013 Awarded Units (in thousands) 24.9 25.4 32.7 Weighted Average Grant Date Fair Value $ 55.46 $ 54.08 $ 45.81 Share-based Compensation Plans Compensation cost for share-based payment arrangements, the actual tax benefit realized from the tax deductions for compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Share-based Compensation Plans 2015 2014 2013 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 63.8 $ 85.4 $ 56.4 Actual Tax Benefit Realized 22.3 29.9 19.7 Total Compensation Cost Capitalized 20.3 23.1 13.2 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income. During the years ended December 31, 2015 , 2014 and 2013 , there were no significant modifications affecting any of the AEP’s share-based payment arrangements. As of December 31, 2015 , there was $72 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP and Prior Plan. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units and AEP career shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.4 years . Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Share-based Compensation Plans 2015 2014 2013 (in millions) Cash Received from Stock Options Exercised $ — $ — $ 5.7 Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised — — 1.0 AEP’s practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. Although management does not currently anticipate any changes to this practice, management is permitted to use treasury shares, shares acquired in the open market specifically for distribution under the 2015 LTIP and Prior Plan or any combination thereof for this purpose. The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Appalachian Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1 . • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM. • A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015 , 2014 and 2013 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015 , 2014 and 2013 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015 , 2014 and 2013 related to the TA: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M and OPCo) Lawrenceburg UPA In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years. I&M operates the plant under an agreement with AEGCo. Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically. UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo) On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo. Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income. The coal transloading expenses in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income. The railcar maintenance revenues in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 , 2014 and 2013 , I&M recorded expenses of $19 million , $24 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2015 , the ownership and investment in OVEC were as follows: December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2015 , both generation plants were operating with environmental controls. Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015 , 2014 and 2013 were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015 , 2014 and 2013 : Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6 Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Indiana Michigan Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1 . • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM. • A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015 , 2014 and 2013 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015 , 2014 and 2013 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015 , 2014 and 2013 related to the TA: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M and OPCo) Lawrenceburg UPA In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years. I&M operates the plant under an agreement with AEGCo. Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically. UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo) On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo. Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income. The coal transloading expenses in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income. The railcar maintenance revenues in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 , 2014 and 2013 , I&M recorded expenses of $19 million , $24 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2015 , the ownership and investment in OVEC were as follows: December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2015 , both generation plants were operating with environmental controls. Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015 , 2014 and 2013 were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015 , 2014 and 2013 : Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6 Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Ohio Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1 . • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM. • A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015 , 2014 and 2013 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015 , 2014 and 2013 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015 , 2014 and 2013 related to the TA: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M and OPCo) Lawrenceburg UPA In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years. I&M operates the plant under an agreement with AEGCo. Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically. UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo) On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo. Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income. The coal transloading expenses in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income. The railcar maintenance revenues in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 , 2014 and 2013 , I&M recorded expenses of $19 million , $24 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2015 , the ownership and investment in OVEC were as follows: December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2015 , both generation plants were operating with environmental controls. Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015 , 2014 and 2013 were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015 , 2014 and 2013 : Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6 Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Public Service Co Of Oklahoma [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1 . • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM. • A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015 , 2014 and 2013 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015 , 2014 and 2013 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015 , 2014 and 2013 related to the TA: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M and OPCo) Lawrenceburg UPA In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years. I&M operates the plant under an agreement with AEGCo. Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically. UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo) On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo. Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income. The coal transloading expenses in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income. The railcar maintenance revenues in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 , 2014 and 2013 , I&M recorded expenses of $19 million , $24 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2015 , the ownership and investment in OVEC were as follows: December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2015 , both generation plants were operating with environmental controls. Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015 , 2014 and 2013 were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015 , 2014 and 2013 : Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6 Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Southwestern Electric Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. See “Corporate Separation” section of Note 1 . • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM. • A Power Supply Agreement between AGR and OPCo for AGR to supply capacity and the energy needs of OPCo’s retail load. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Prior to January 1, 2014, power and natural gas risk management activities were allocated under the SIA to former members of the Interconnection Agreement, PSO and SWEPCo. Risk management activities primarily include power and natural gas physical transactions, financially-settled swaps and exchange-traded futures. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. The SIA was designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controlled the distribution of revenues and expenses. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2015 , 2014 and 2013 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2015 , 2014 and 2013 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2015 , 2014 and 2013 related to the TA: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2015 , 2014 and 2013 : Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEPEP, APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M and OPCo) Lawrenceburg UPA In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. Effective January 1, 2014, the Lawrenceburg UPA was assigned by OPCo to AGR. AGR has an option to extend the UPA for an additional two years. I&M operates the plant under an agreement with AEGCo. Under the UPA, AGR pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically. UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, OPCo, PSO and SWEPCo) On August 1, 2013, OPCo transferred its interest in Cook Coal Terminal to AEGCo. Cook Coal Terminal performs coal transloading and storage services at cost for I&M and OPCo. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income. The coal transloading expenses in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. Beginning August 1, 2013 and through corporate separation in Ohio on December 31, 2013, Cook Coal Terminal also performed railcar maintenance services at cost for OPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income. The railcar maintenance revenues in 2015 , 2014 and 2013 were as follows: AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo, I&M and OPCo) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 , 2014 and 2013 , I&M recorded expenses of $19 million , $24 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2015 , the ownership and investment in OVEC were as follows: December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures totaling $1.3 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2015 , both generation plants were operating with environmental controls. Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2015 , 2014 and 2013 were: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2015 , 2014 and 2013 : Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6 Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .
Appalachian Power Co [Member]
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .
Indiana Michigan Power Co [Member]
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .
Ohio Power Co [Member]
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .
Public Service Co Of Oklahoma [Member]
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .
Southwestern Electric Power Co [Member]
Variable Interest Entities	VARIABLE INTEREST ENTITIES The disclosures in this note apply to all Registrants unless indicated otherwise. The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. AEP is the primary beneficiary of Sabine, DCC Fuel, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, AEP Credit, a protected cell of EIS and Transource Energy. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2015 , 2014 and 2013 were $152 million , $151 million and $155 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the years ended December 31, 2015 , 2014 and 2013 were $115 million , $109 million and $153 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets. Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Transition Funding has securitized transition assets of $1.3 billion and $1.6 billion as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo’s equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $185 million and $230 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $86 million and $110 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding’s securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo’s under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo’s equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $342 million and $364 million as of December 31, 2015 and 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $328 million and $350 million as of December 31, 2015 and 2014 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit is a wholly-owned subsidiary of Parent. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on AEP’s control of AEP Credit, management concluded that AEP is the primary beneficiary and is required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets. See “Securitized Accounts Receivables - AEP Credit” section of Note 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2015, 2014 and 2013 were $29 million , $32 million and $31 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity and AEP’s equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP has provided capital contributions to Transource Energy of $47 million and $23 million , in 2015 and 2014, respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million . Non-Consolidated Significant Variable Interests DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the years ended December 31, 2015 , 2014 and 2013 were $93 million , $56 million and $60 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7 AEP and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. AEP has no interest or control in the “Allegheny Series”. AEP is not required to consolidate PATH-WV as AEP is not the primary beneficiary, although AEP holds a significant variable interest in PATH-WV. AEP’s equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets. AEP and FirstEnergy share the returns and losses equally in PATH-WV. AEP’s subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. AEP’s investment in PATH-WV was: December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0 As of December 31, 2015 , AEP’s $21 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2015 , 2014 and 2013 were $232 million , $268 million and $252 million . Total billings to OPCo from AEGCo for the year ended December 31, 2013 was $148 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2015 and 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Appalachian Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Ohio Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, plant and equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances for the years ended December 31, 2015 and 2014 : Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75 APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55 I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45 OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50 PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40 SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are Not Meaningful (NM) for APCo, I&M, OPCo and PSO for 2015 , 2014 and 2013 . AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2015 and 2014 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.18 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2015 and 2014 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.80 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant, including a $95 million second quarter increase and other adjustments recorded in 2015: Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of allowance for equity funds used during construction are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.

Cost Reduction Programs

Cost Reduction Programs	12 Months Ended
	Dec. 31, 2015
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Appalachian Power Co [Member]
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Indiana Michigan Power Co [Member]
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Ohio Power Co [Member]
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Public Service Co Of Oklahoma [Member]
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Southwestern Electric Power Co [Member]
Cost Reduction Programs	COST REDUCTION PROGRAMS The disclosures in this note apply to all Registrants unless indicated otherwise. 2014 Disposition Plant Severance Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants’ disposition plant severance activity for the twelve months ended December 31, 2015 is described in the following table: Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant. The Registrants recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amounts incurred in 2014 by the Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income. Of AEP’s cumulative expense, approximately 33% was within the Generation & Marketing segment and 67% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the balance sheets. The Registrants incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. 2012 Sustainable Cost Reductions In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrants recorded charges to Other Operation expense for the year ended December 31, 2013 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The amounts incurred by Registrants were as follows: Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (a) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a) 1.29 0.88 1.06 0.95 2014 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 559.8 $ 389.9 $ 493.2 $ 190.9 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations 1.14 0.79 0.99 0.32 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b) 0.01 0.01 0.02 0.07 Total Basic Earnings per Share Attributable to AEP Common Shareholders (a) 1.15 0.80 1.01 0.39 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations 1.14 0.79 0.99 0.32 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b) 0.01 0.01 0.02 0.07 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a) 1.15 0.80 1.01 0.39 (a) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (b) Relates to sale of AEPRO (see Note 7 ).
Appalachian Power Co [Member]
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Indiana Michigan Power Co [Member]
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Ohio Power Co [Member]
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Public Service Co Of Oklahoma [Member]
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Southwestern Electric Power Co [Member]
Quarterly Financial Information [Text Block]	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).

Goodwill and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Text Block]	GOODWILL AND OTHER INTANGIBLE ASSETS The disclosures in this note apply to AEP only. Goodwill The changes in AEP’s carrying amount of goodwill for the years ended December 31, 2015 and 2014 by operating segment are as follows: Corporate and Other Generation and Marketing AEP Consolidated (in millions) Balance as of December 31, 2013 $ 75.9 $ 15.4 $ 91.3 Impairment Losses — — — Balance as of December 31, 2014 75.9 15.4 91.3 Impairment Losses — — — Goodwill Written Off Related to Sale of AEPRO (38.8 ) (a) — (38.8 ) Balance as of December 31, 2015 $ 37.1 $ 15.4 $ 52.5 (a) The goodwill of $38.8 million related to AEPRO is included in Other Classes of Assets That Are Not Major as of December 31, 2014 in Note 7 . See “Dispositions” section of Note 7 for additional information. In the fourth quarters of 2015 and 2014 , annual impairment tests were performed. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. AEP does not have any accumulated impairment on existing goodwill. Other Intangible Assets Acquired intangible assets subject to amortization were $2 million and $ 5 million as of December 31, 2015 and 2014 , respectively, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows: December 31, 2015 2014 Amortization Life Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (in years) (in millions) Acquired Customer Contracts 5 $ 58.3 $ 56.5 $ 58.3 $ 53.4 Amortization of intangible assets was $3 million , $5 million and $14 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The estimated total amortization is $2 million for 2016.

Organization and Summary of S30

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Other Temporary Investments	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 its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 .
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 . Barging Activities (Applies to AEP) AEP River Operations’ revenue, which is presented in Discontinued Operations, was recognized based on percentage of voyage completion. The proportion of freight transportation revenue to be recognized was determined by applying a percentage to the contractual charges for such services. The percentage was determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract. The position of the barge at accounting period end was determined by AEP’s computerized barge tracking system.
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins. I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and 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. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Stock-based Compensation	Stock-Based Compensation Plans (Applies to AEP) As of December 31, 2015 , AEP had performance units and restricted stock units outstanding under the American Electric Power System Long-Term Incentive Plan (LTIP). Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares, and are reinvested in such shares at the closing market price on the dividend payments date. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense using the straight-line single-option method. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2015 , 2014 and 2013 is based on awards ultimately expected to vest. Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures. Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. For the years ended December 31, 2015 , 2014 and 2013 , compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units. See Note 15 for additional discussion.
Earnings Per Share	Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
Appalachian Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds.
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Indiana Michigan Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins. I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and 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. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Ohio Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds.
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Public Service Co Of Oklahoma [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Southwestern Electric Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and nonregulated wind farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled. OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based. Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In accordance with management’s 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. In December 2013, the FERC issued orders approving the creation of a PCA and a PSA, effective January 1, 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. Effective June 1, 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2015 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s nonregulated business, management records allowances at the lower of cost or market. Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and 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. Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia (upon securitization in November 2013) for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo and in West Virginia for APCo (prior to securitization in November 2013) are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. Prior to corporate separation, none of the margins from off-system sales were given to customers through the FAC in Ohio for OPCo. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrants initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 .
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, the concentration limits must not exceed: • 3% in any single issuer. • 5% for private placements. • 5% for convertible securities. • 60% for bonds rated AA+ or lower. • 50% for bonds rated A+ or lower. • 10% for bonds rated BBB- or lower. For obligations of non-government issuers within the fixed income portfolio, the following limitations apply: • AAA rated debt: a single issuer should account for no more than 5% of the portfolio. • AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. • Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. • No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. Each investment manager’s portfolio is compared to a diversified benchmark index. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Benefit Plans (Policies)

Benefit Plans (Policies)	12 Months Ended
	Dec. 31, 2015
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Appalachian Power Co [Member]
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Indiana Michigan Power Co [Member]
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Ohio Power Co [Member]
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Public Service Co Of Oklahoma [Member]
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Southwestern Electric Power Co [Member]
Pension And Other Postretirement Plans	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. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	12 Months Ended
	Dec. 31, 2015
Derivatives and Hedging	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 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. 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 are 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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. In addition, a majority of the Registrants’ 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 in excess of $50 million . 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.” Credit Risk Management limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income.
Appalachian Power Co [Member]
Derivatives and Hedging	Credit Risk Management limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. In addition, a majority of the Registrants’ 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 in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. 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. 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.
Indiana Michigan Power Co [Member]
Derivatives and Hedging	The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Credit Risk Management limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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. In addition, a majority of the Registrants’ 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 in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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.
Ohio 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel 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 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. 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. In addition, a majority of the Registrants’ 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 in excess of $50 million . 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral.
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	The Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Credit Risk Management limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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. In addition, a majority of the Registrants’ 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 in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. 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.
Southwestern Electric 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’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. The Registrants utilize financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. The Registrants do not hedge all fuel price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, to a lesser extent, 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 and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” 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 Registrants reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the 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 is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). 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. Credit Risk Management limits credit risk in 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. When management uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrants are obligated to post an additional amount of collateral if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrants have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. In addition, a majority of the Registrants’ 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 in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2015
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Appalachian Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Indiana Michigan Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Ohio Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Public Service Co Of Oklahoma [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Southwestern Electric Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
	Dec. 31, 2015
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Appalachian Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Indiana Michigan Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Ohio Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Public Service Co Of Oklahoma [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Southwestern Electric Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Leases (Policies)

Leases (Policies)	12 Months Ended
	Dec. 31, 2015
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Appalachian Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Indiana Michigan Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Ohio Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Public Service Co Of Oklahoma [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Southwestern Electric Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.

Stock-Based Compensation (Polic

Stock-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2015
Stock-based Compensation	Stock-Based Compensation Plans (Applies to AEP) As of December 31, 2015 , AEP had performance units and restricted stock units outstanding under the American Electric Power System Long-Term Incentive Plan (LTIP). Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares, and are reinvested in such shares at the closing market price on the dividend payments date. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense using the straight-line single-option method. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2015 , 2014 and 2013 is based on awards ultimately expected to vest. Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures. Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. For the years ended December 31, 2015 , 2014 and 2013 , compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units. See Note 15 for additional discussion.
Stock Based Compensation [Member]
Stock-based Compensation	AEP’s long-term incentive plan available for eligible employees and directors, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2015 , 9,964,153 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. To the extent the issuance of a share that is subject to an outstanding award under the Prior Plan, the issuance of that share will take place under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of AEP’s Board of Directors (HR Committee). AEP’s practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. Although management does not currently anticipate any changes to this practice, management is permitted to use treasury shares, shares acquired in the open market specifically for distribution under the 2015 LTIP and Prior Plan or any combination thereof for this purpose. The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units and AEP career shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.4 years .
Employee Stock Option [Member]
Stock-based Compensation	AEP did not grant stock options in 2015 , 2014 or 2013 . AEP did have outstanding stock options from grants in earlier periods that were exercised in 2013. As of December 31, 2015 , AEP has no outstanding stock options. AEP recorded compensation cost for stock options over the vesting period based on the fair value on the grant date. The 2015 LTIP specifies a maximum contractual term of 10 years for stock options.
Performance Units [Member]
Stock-based Compensation	Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to the Standard and Poor’s 500 Electric Utilities Index and (b) three -year cumulative earnings per share measured relative to a target approved by AEP’s Board of Directors Pursuant to the 2015 LTIP, AEP’s performance units are paid out in cash rather than AEP shares. For that reason, AEP’s performance units no longer reduce the aggregate share authorization. AEP’s performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. The number of performance units held at the end of the three year performance period is multiplied by the performance score to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee. Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, their performance units are mandatorily deferred as AEP career shares. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over a three-year vesting period. The liability for both the performance units and AEP career shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value.
Restricted Shares and Restricted Stock Units [Member]
Stock-based Compensation	The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends. Additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into a share of AEP common stock upon vesting, except for AEP’s officers subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash. In 2014, there were no RSUs granted to Section 16 officers due to a change that deferred granting these and other awards until February 2015. For RSUs paid in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Stock-based Compensation	AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.
Appalachian Power Co [Member]
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.
Indiana Michigan Power Co [Member]
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.
Ohio Power Co [Member]
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.
Public Service Co Of Oklahoma [Member]
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.
Southwestern Electric Power Co [Member]
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether AEP is the primary beneficiary of a VIE, management considers factors such as equity at risk, the amount of the VIE’s variability AEP absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently.

Property, Plant and Equipment (

Property, Plant and Equipment (Policies)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Appalachian Power Co [Member]
Property, Plant and Equipment	For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Ohio Power Co [Member]
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Organization and Summary of S39

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Basic and Diluted EPS Calculations	Years Ended December 31, 2015 2014 2013 (in millions, except per share data) $/share $/share $/share Income from Continuing Operations $ 1,768.6 $ 1,590.5 $ 1,473.9 Less: Net Income Attributable to Noncontrolling Interests 5.2 4.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,763.4 $ 1,586.3 $ 1,470.2 Weighted Average Number of Basic Shares Outstanding 490.3 $ 3.59 488.6 $ 3.24 486.6 $ 3.02 Weighted Average Dilutive Effect of Restricted Stock Units 0.3 — 0.3 — 0.4 — Weighted Average Number of Diluted Shares Outstanding 490.6 $ 3.59 488.9 $ 3.24 487.0 $ 3.02
Supplementary Information	Years Ended December 31, Related Party Transactions 2015 2014 2013 (in millions) AEP Revenues – Other Revenues: OVEC – Barging and Other Transportation Services (a) $ 0.1 $ 24.0 $ 20.9 AEP Expenses – Purchased Electricity for Resale: OVEC 241.7 268.5 289.2 (a) AEP did not ship coal to OVEC in 2015. Years Ended December 31, Cash Flow Information 2015 2014 2013 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 857.2 $ 838.5 $ 882.1 Income Taxes 120.2 117.3 (54.8 ) Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 150.2 135.1 181.6 Construction Expenditures Included in Current Liabilities as of December 31, 741.4 559.3 492.4 Construction Expenditures Included in Noncurrent Liabilities as of December 31, 51.6 — — Construction Expenditures Included in Noncurrent Assets as of December 31, 10.5 — — Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, 37.9 44.5 — Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.2 3.4 4.4 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2
Appalachian Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2
Indiana Michigan Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2
Ohio Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2
Public Service Co Of Oklahoma [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2
Southwestern Electric Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 2013 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,441.4 $ 334.2 $ 175.8 $ 358.0 $ 94.6 $ 177.3 Amortization of Certain Securitized Assets 248.2 — — 20.0 — — Amortization of Regulatory Assets and Liabilities 22.9 8.4 1.9 4.6 1.1 1.9 Total Depreciation and Amortization $ 1,712.5 $ 342.6 $ 177.7 $ 382.6 $ 95.7 $ 179.2

New Accounting Pronouncements (

New Accounting Pronouncements (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1
Appalachian Power Co [Member]
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1
Indiana Michigan Power Co [Member]
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1
Ohio Power Co [Member]
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1
Public Service Co Of Oklahoma [Member]
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1
Southwestern Electric Power Co [Member]
Schedule of New Accounting Pronouncements	Company December 31, 2014 (in millions) AEP $ 88.5 APCo 21.6 I&M 7.8 OPCo 10.3 PSO 4.3 SWEPCo 8.1

Comprehensive Income (Tables)

Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amounts Reclassified from AOCI (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amounts Reclassified from AOCI 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (8.1 ) $ (30.2 ) $ 4.2 $ 112.0 $ (414.9 ) $ (337.0 ) Change in Fair Value Recognized in AOCI 10.4 2.6 2.6 — 176.6 192.2 Amounts Reclassified from AOCI (2.1 ) 4.6 — 21.9 — 24.4 Net Current Period Other Comprehensive Income 8.3 7.2 2.6 21.9 176.6 216.6 Pension and OPEB Adjustment Related to Mitchell Plant — — — — 5.2 5.2 Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 )
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. AEP Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Reclassified from AOCI Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Vertically Integrated Utilities Revenues $ — $ — $ (1.1 ) Generation & Marketing Revenues (48.1 ) 59.1 (9.7 ) Purchased Electricity for Resale 29.1 (39.1 ) 7.6 Regulatory Assets/(Liabilities), Net (a) — (2.8 ) — Subtotal – Commodity (19.0 ) 17.2 (3.2 ) Interest Rate and Foreign Currency: Interest Expense 2.9 6.1 7.1 Subtotal – Interest Rate and Foreign Currency 2.9 6.1 7.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (16.1 ) 23.3 3.9 Income Tax (Expense) Credit (5.6 ) 8.2 1.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.5 ) 15.1 2.5 Pension and OPEB Amortization of Prior Service Cost (Credit) (19.5 ) (20.6 ) (21.0 ) Amortization of Actuarial (Gains)/Losses 21.3 28.0 54.7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.8 7.4 33.7 Income Tax (Expense) Credit 0.6 2.6 11.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.2 4.8 21.9 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (9.3 ) $ 19.9 $ 24.4
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amounts Reclassified from AOCI — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amounts Reclassified from AOCI (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.6 ) $ 2.1 $ 19.1 $ (50.5 ) $ (29.9 ) Change in Fair Value Recognized in AOCI 0.7 — — 29.7 30.4 Amounts Reclassified from AOCI — 1.0 1.4 — 2.4 Net Current Period Other Comprehensive Income 0.7 1.0 1.4 29.7 32.8 Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.1 ) Purchased Electricity for Resale — (0.5 ) 0.1 Regulatory Assets/(Liabilities), Net (a) — (2.2 ) — Subtotal – Commodity — (2.7 ) — Interest Rate and Foreign Currency: Interest Expense (0.4 ) 1.2 1.5 Subtotal – Interest Rate and Foreign Currency (0.4 ) 1.2 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) (1.5 ) 1.5 Income Tax (Expense) Credit (0.1 ) (0.5 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) (1.0 ) 1.0 Pension and OPEB Amortization of Prior Service Cost (Credit) (5.1 ) (5.1 ) (5.1 ) Amortization of Actuarial (Gains)/Losses 2.3 3.1 7.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.8 ) (2.0 ) 2.2 Income Tax (Expense) Credit (1.0 ) (0.7 ) 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) (1.3 ) 1.4 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (2.1 ) $ (2.3 ) $ 2.4
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amounts Reclassified from AOCI — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amounts Reclassified from AOCI (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.4 ) $ (19.7 ) $ 4.2 $ (13.0 ) $ (28.9 ) Change in Fair Value Recognized in AOCI 0.5 2.3 — 8.5 11.3 Amounts Reclassified from AOCI — 1.4 0.7 — 2.1 Net Current Period Other Comprehensive Income 0.5 3.7 0.7 8.5 13.4 Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 )
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.2 ) Purchased Electricity for Resale — (0.8 ) 0.2 Regulatory Assets/(Liabilities), Net (a) — (1.0 ) — Subtotal – Commodity — (1.8 ) — Interest Rate and Foreign Currency: Interest Expense 1.7 2.4 2.2 Subtotal – Interest Rate and Foreign Currency 1.7 2.4 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.7 0.6 2.2 Income Tax (Expense) Credit 0.6 0.2 0.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.1 0.4 1.4 Pension and OPEB Amortization of Prior Service Cost (Credit) (0.9 ) (0.8 ) (0.8 ) Amortization of Actuarial (Gains)/Losses 0.9 1.1 1.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 0.3 1.1 Income Tax (Expense) Credit — 0.1 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 0.2 0.7 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.1 $ 0.6 $ 2.1
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amounts Reclassified from AOCI (0.1 ) (1.4 ) — — (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) — — (1.5 ) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ (0.9 ) $ 8.1 $ 45.9 $ (218.8 ) $ (165.7 ) Change in Fair Value Recognized in AOCI 1.0 — — 65.4 66.4 Amounts Reclassified from AOCI — (1.3 ) 12.5 — 11.2 Net Current Period Other Comprehensive Income (Loss) 1.0 (1.3 ) 12.5 65.4 77.6 Distribution of Cook Coal Terminal to Parent — — — 19.6 19.6 Distribution of OPCo Generation to Parent — 0.2 — 75.4 75.6 Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Electric Generation, Transmission and Distribution Revenues $ — $ — $ (0.4 ) Purchased Electricity for Resale — — 0.6 Other Operation Expense — — (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.2 ) — Subtotal – Commodity — (0.2 ) 0.1 Interest Rate and Foreign Currency: Interest Expense (2.0 ) (2.1 ) (2.1 ) Subtotal – Interest Rate and Foreign Currency (2.0 ) (2.1 ) (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (2.0 ) (2.3 ) (2.0 ) Income Tax (Expense) Credit (0.7 ) (0.8 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.3 ) (1.5 ) (1.3 ) Pension and OPEB Amortization of Prior Service Cost (Credit) — — (5.8 ) Amortization of Actuarial (Gains)/Losses — — 25.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — — 19.2 Income Tax (Expense) Credit — — 6.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — — 12.5 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1.3 ) $ (1.5 ) $ 11.2
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ 6.5 $ 6.5 Change in Fair Value Recognized in AOCI 0.1 — 0.1 Amounts Reclassified from AOCI — (0.8 ) (0.8 ) Net Current Period Other Comprehensive Income (Loss) 0.1 (0.8 ) (0.7 ) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8
Reclassifications from Accumulated Other Comprehensive Income (Loss)	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Regulatory Assets/(Liabilities), Net (a) $ — $ (0.1 ) $ — Subtotal – Commodity — (0.1 ) — Interest Rate and Foreign Currency: Interest Expense (1.2 ) (1.1 ) (1.2 ) Subtotal – Interest Rate and Foreign Currency (1.2 ) (1.1 ) (1.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.2 ) (1.2 ) (1.2 ) Income Tax (Expense) Credit (0.4 ) (0.4 ) (0.4 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (0.8 ) $ (0.8 ) $ (0.8 )
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amounts Reclassified from AOCI — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amounts Reclassified from AOCI — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2013 Cash Flow Hedges Pension and OPEB Commodity Interest Rate and Foreign Currency Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2012 $ — $ (15.6 ) $ 4.8 $ (7.1 ) $ (17.9 ) Change in Fair Value Recognized in AOCI 0.1 — — 7.4 7.5 Amounts Reclassified from AOCI (0.1 ) 2.3 (0.3 ) — 1.9 Net Current Period Other Comprehensive Income (Loss) — 2.3 (0.3 ) 7.4 9.4 Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 )
Reclassifications from Accumulated Other Comprehensive Income (Loss)	SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) Amount of (Gain) Loss Years Ended December 31, 2015 2014 2013 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Other Operation Expense $ — $ — $ (0.1 ) Regulatory Assets/(Liabilities), Net (a) — (0.1 ) — Subtotal – Commodity — (0.1 ) (0.1 ) Interest Rate and Foreign Currency: Interest Expense 3.1 3.5 3.5 Subtotal – Interest Rate and Foreign Currency 3.1 3.5 3.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 3.1 3.4 3.4 Income Tax (Expense) Credit 1.1 1.2 1.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2.0 2.2 2.2 Pension and OPEB Amortization of Prior Service Cost (Credit) (1.9 ) (1.9 ) (1.8 ) Amortization of Actuarial (Gains)/Losses 0.4 0.5 1.4 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.5 ) (1.4 ) (0.4 ) Income Tax (Expense) Credit (0.5 ) (0.5 ) (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) (0.9 ) (0.3 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 1.0 $ 1.3 $ 1.9 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Effects of Regulation (Tables)

Effects of Regulation (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Generating Units to be Retired Before or During 2016	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3
Regulatory Assets	AEP December 31, Remaining Recovery Period 2015 2014 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 38.9 $ 121.2 1 year Under-recovered Fuel Costs - does not earn a return 76.3 5.4 1 year Total Current Regulatory Assets $ 115.2 $ 126.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Storm Related Costs $ 24.2 $ 20.2 Plant Retirement Costs - Materials and Supplies 20.9 — West Virginia Vegetation Management Program — 20.4 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 59.8 — Storm Related Costs 18.2 100.4 Peak Demand Reduction/Energy Efficiency 13.1 9.0 Carbon Capture and Storage Product Validation Facility — 13.3 IGCC Pre-Construction Costs — 10.8 Ormet Special Rate Recovery Mechanism — 10.5 Other Regulatory Assets Pending Final Regulatory Approval 31.7 42.7 Total Regulatory Assets Pending Final Regulatory Approval 167.9 227.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 577.4 — 29 years Ohio Capacity Deferral 358.7 422.1 3 years Ohio Phase-In Recovery Rider 304.5 377.5 3 years Meter Replacement Costs 90.4 59.2 12 years Ohio Distribution Decoupling 37.5 35.1 2 years Mitchell Plant Transfer 19.3 — 25 years Ohio Transmission Cost Recovery Rider 12.3 27.9 1 year Red Rock Generating Facility 9.3 9.5 41 years Storm Related Costs 8.8 13.0 3 years Other Regulatory Assets Approved for Recovery 36.7 29.1 various Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 1,410.5 1,273.1 12 years Income Taxes, Net 1,385.3 1,268.3 52 years Unamortized Loss on Reacquired Debt 148.7 65.7 30 years Storm Related Costs 94.6 26.0 5 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Plant Retirement Costs - Asset Retirement Obligation Costs 58.0 — 25 years Postemployment Benefits 42.6 39.2 5 years Medicare Subsidy 41.8 46.5 9 years Vegetation Management 36.9 5.4 6 years Peak Demand Reduction/Energy Efficiency 33.3 62.4 2 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years United Mine Workers of America Pension Withdrawal 14.4 25.4 10 years Distribution Investment Rider 12.3 9.9 2 years Carbon Capture and Storage Product Validation Facility 11.7 — 5 years IGCC Pre-Construction Costs 10.9 — 25 years Unrealized Loss on Forward Commitments 10.7 9.7 2 years Transmission Cost Recovery Factor 9.9 15.4 1 year Deferred System Reliability Rider Expenses 9.9 8.3 1 year Indiana Capacity Costs 7.5 25.1 1 year gridSMART ® Costs 4.5 15.9 2 years PJM Expense 4.1 21.9 2 years Other Regulatory Assets Approved for Recovery 68.5 53.6 various Total Regulatory Assets Approved for Recovery 4,972.4 4,036.4 Total Noncurrent Regulatory Assets $ 5,140.3 $ 4,263.7
Regulatory Liabilities	AEP December 31, Remaining 2015 2014 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 84.8 $ — 1 year Over-recovered Fuel Costs - does not pay a return 29.1 55.2 1 year Total Current Regulatory Liabilities $ 113.9 $ 55.2 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 16.8 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 52.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 2,656.5 2,660.3 (a) Louisiana Refundable Construction Financing Costs 37.4 58.2 3 years Advanced Metering Infrastructure Surcharge 21.2 43.7 5 years Deferred Investment Tax Credits 14.7 25.8 43 years Excess Earnings 10.6 11.1 38 years Other Regulatory Liabilities Approved for Payment 20.5 3.8 various Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Deferred Investment Tax Credits 113.3 112.6 47 years Transition Charges 46.5 46.8 12 years Spent Nuclear Fuel Liability 43.4 43.5 (b) Unrealized Gain on Forward Commitments 33.8 92.2 17 years Deferred Wind Power Costs 11.8 — 2 years Advanced Metering Costs 11.4 — 1 year Indiana Off-system Sales Margin Sharing — 19.4 Other Regulatory Liabilities Approved for Payment 37.7 28.1 various Total Regulatory Liabilities Approved for Payment 3,695.3 3,840.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,736.1 $ 3,892.4 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned.
Appalachian Power Co [Member]
Regulated Generating Units to be Retired Before or During 2016	December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3
Regulatory Assets	APCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 27.3 $ 60.7 1 year Under-recovered Fuel Costs - does not earn a return 59.6 5.4 1 year Total Current Regulatory Assets $ 86.9 $ 66.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.3 $ — Vegetation Management Program - West Virginia — 19.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 32.7 — Peak Demand Reduction/Energy Efficiency - Virginia 12.7 8.8 Amos Plant Transfer Costs - West Virginia 2.0 1.4 Storm Related Costs - West Virginia — 65.2 Carbon Capture and Storage Product Validation Facility - West Virginia, FERC — 13.3 IGCC Pre-Construction Costs - West Virginia, FERC — 10.8 Expanded Net Energy Charge - Coal Inventory — 3.4 Expanded Net Energy Charge - Construction Surcharge — 2.3 Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC — 1.3 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.1 Total Regulatory Assets Pending Final Regulatory Approval 57.3 125.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 86.5 — 24 years Storm Related Costs - Virginia 8.8 13.0 3 years RTO Formation/Integration Costs 2.1 2.5 4 years Regulatory Assets Currently Not Earning a Return Income Taxes, Net 441.7 381.7 25 years Pension and OPEB Funded Status 217.6 212.5 12 years Unamortized Loss on Reacquired Debt 101.5 11.1 30 years Virginia Transmission Rate Adjustment Clause 74.6 53.2 2 years Storm Related Costs - West Virginia 63.5 8.5 5 years Vegetation Management Program - West Virginia 31.2 — 6 years Postemployment Benefits 19.6 17.8 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 11.7 — 5 years IGCC Pre-Construction Costs - West Virginia, FERC 9.6 — 5 years Medicare Subsidy - West Virginia, FERC 5.3 5.9 9 years Virginia Generation Rate Adjustment Clause 5.2 3.8 3 years Deferred Restructuring Costs - West Virginia 4.5 6.5 3 years Peak Demand Reduction/Energy Efficiency - West Virginia 3.5 0.9 2 years Uncollected Accounts - West Virginia 3.5 — 5 years Asset Retirement Obligation 2.4 4.4 2 years Transmission Agreement Phase-In - West Virginia 1.7 2.9 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.2 — 7 years Unrealized Loss on Forward Commitments 0.6 4.1 2 years Virginia Environmental Rate Adjustment Clause — 3.3 Other Regulatory Assets Approved for Recovery 0.6 0.1 various Total Regulatory Assets Approved for Recovery 1,096.9 732.2 Total Noncurrent Regulatory Assets $ 1,154.2 $ 857.9
Regulatory Liabilities	APCo December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Expanded Net Energy Charge - Construction Surcharge $ — $ 5.4 Deferred Wind Power Costs - Virginia — 4.5 Felman Special Rate Mechanism - West Virginia — 2.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 12.0 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 612.9 617.3 (a) Deferred Investment Tax Credits 1.0 1.3 43 years Regulatory Liabilities Currently Not Paying a Return Deferred Wind Power Costs - Virginia 11.8 — 2 years Unrealized Gain on Forward Commitments 8.4 19.7 2 years Consumer Rate Relief - West Virginia 2.9 2.6 1 year Other Regulatory Liabilities Approved for Payment 0.1 — various Total Regulatory Liabilities Approved for Payment 637.1 640.9 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 637.1 $ 652.9 (a) Relieved as removal costs are incurred
Indiana Michigan Power Co [Member]
Regulated Generating Units to be Retired Before or During 2016	Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Regulatory Assets	I&M December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 7.5 $ 0.8 1 year Under-recovered Fuel Costs - does not earn a return 4.1 — 1 year Total Current Regulatory Assets $ 11.6 $ 0.8 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 — Cook Plant Turbine 9.7 6.6 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 4.2 1.2 Stranded Costs on Abandoned Plants 3.9 3.9 Rockport Plant Dry Sorbent Injection System - Indiana 2.8 0.1 Storm Related Costs - Indiana — 1.1 Other Regulatory Assets Pending Final Regulatory Approval — 0.7 Total Regulatory Assets Pending Final Regulatory Approval 59.3 13.6 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 260.3 — 29 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.6 6.9 23 years RTO Formation/Integration Costs 1.5 1.8 4 years Other Regulatory Assets Approved for Recovery 1.0 0.8 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 246.8 255.0 29 years Pension and OPEB Funded Status 126.4 107.8 12 years Cook Plant Nuclear Refueling Outage Levelization 26.8 38.0 3 years Unamortized Loss on Reacquired Debt 12.0 13.3 17 years Postemployment Benefits 10.7 10.0 5 years Peak Demand Reduction/Energy Efficiency 10.6 16.6 2 years Medicare Subsidy 9.2 10.2 9 years Litigation Settlement - Indiana 8.6 9.5 10 years Capacity Costs - Indiana 7.5 25.1 1 year Off-system Sales Margin Sharing - Indiana 6.8 — 2 years PJM Expense - Indiana 4.1 21.9 2 years Unrealized Loss on Forward Commitments 3.2 0.5 2 years Storm Related Costs - Indiana 1.8 — 1 year Deferred Cook Plant Life Cycle Management Project Costs - Indiana — 2.2 Deferred Restructuring Costs - Michigan — 1.2 Other Regulatory Assets Approved for Recovery 1.1 1.8 various Total Regulatory Assets Approved for Recovery 745.0 522.6 Total Noncurrent Regulatory Assets $ 804.3 $ 536.2
Regulatory Liabilities	I&M December 31, Remaining Refund Period Regulatory Liabilities: 2015 2014 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 0.3 $ — 1 year Over-recovered Fuel Costs - does not pay a return — 7.1 Total Current Regulatory Liabilities $ 0.3 $ 7.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Other Regulatory Liabilities Pending Final Regulatory Determination $ — $ 0.1 Total Regulatory Liabilities Pending Final Regulatory Determination — 0.1 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 350.6 378.5 (a) Regulatory Liabilities Currently Not Paying a Return Excess Asset Retirement Obligations for Nuclear Decommissioning Liability 636.5 694.9 (b) Spent Nuclear Fuel Liability 43.4 43.5 (b) Deferred Investment Tax Credits 35.0 38.3 21 years Unrealized Gain on Forward Commitments 7.1 19.6 2 years River Transportation Division Expenses 1.9 5.3 1 year Off-system Sales Margin Sharing - Indiana — 19.4 Other Regulatory Liabilities Approved for Payment 1.7 0.1 various Total Regulatory Liabilities Approved for Payment 1,076.2 1,199.6 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,076.2 $ 1,199.7 (a) Relieved as removal costs are incurred. (b) Relieved when plant is decommissioned.
Ohio Power Co [Member]
Regulated Generating Units to be Retired Before or During 2016	Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Regulatory Assets	OPCo December 31, Remaining Recovery Period Regulatory Assets: 2015 2014 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ — $ 10.5 gridSMART ® Costs 1.3 — Total Regulatory Assets Pending Final Regulatory Approval 1.3 10.5 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Capacity Deferral 358.7 422.1 3 years Phase-In Recovery Rider 304.5 377.5 3 years Distribution Decoupling 37.5 35.1 2 years Transmission Cost Recovery Rider 12.3 27.9 1 year RTO Formation/Integration Costs 3.1 3.7 4 years Economic Development Rider — 4.1 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 219.4 195.4 12 years Income Taxes, Net 129.0 137.5 31 years Distribution Investment Rider 12.3 9.9 2 years Unamortized Loss on Reacquired Debt 10.4 11.7 23 years Medicare Subsidy 9.3 10.3 9 years Postemployment Benefits 7.3 6.1 5 years gridSMART ® Costs 4.5 15.9 2 years Partnership with Ohio Contribution 2.4 0.4 3 years Storm Related Costs 0.1 15.2 1 year Peak Demand Reduction/Energy Efficiency — 29.1 Enhanced Service Reliability Plan — 6.5 Other Regulatory Assets Approved for Recovery 0.9 — various Total Regulatory Assets Approved for Recovery 1,111.7 1,308.4 Total Noncurrent Regulatory Assets $ 1,113.0 $ 1,318.9
Regulatory Liabilities	OPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 27.6 $ 46.3 1 year Total Current Regulatory Liabilities $ 27.6 $ 46.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ 40.6 $ 35.2 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.4 Total Regulatory Liabilities Pending Final Regulatory Determination 40.8 35.6 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 422.3 423.2 (a) Economic Development Rider 5.0 — 2 years Basic Transmission Cost Rider 4.9 — 2 years Deferred Investment Tax Credits — 0.1 Regulatory Liabilities Currently Not Paying a Return Unrealized Gain on Forward Commitments 15.3 47.3 17 years Regulatory Settlement 9.0 — 2 years Enhanced Service Reliability Plan 8.0 — 2 years Deferred Asset Phase-In Rider 5.1 7.1 5 years Peak Demand Reduction/Energy Efficiency 1.5 — 2 years Storm Related Costs 1.3 — 1 year Low Income Customers/Economic Recovery 1.0 1.3 1 year Other Regulatory Liabilities Approved for Payment — 0.1 Total Regulatory Liabilities Approved for Payment 473.4 479.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 514.2 $ 514.7 (a) Relieved as removal costs are incurred.
Public Service Co Of Oklahoma [Member]
Regulated Generating Units to be Retired Before or During 2016	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Regulatory Assets	PSO December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ — $ 35.7 Total Current Regulatory Assets $ — $ 35.7 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Storm Related Costs $ 12.3 $ 16.6 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.1 Total Regulatory Assets Pending Final Regulatory Approval 13.4 17.7 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 35.8 — 11 years Red Rock Generating Facility 9.3 9.5 41 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 95.1 89.7 12 years Storm Related Costs 15.4 — 4 years Peak Demand Reduction/Energy Efficiency 11.8 9.2 2 years Deferred System Reliability Rider Expenses 9.9 8.3 1 year Unamortized Loss on Reacquired Debt 6.8 8.0 17 years Income Taxes, Net 6.1 1.9 35 years Vegetation Management 4.5 2.9 1 year Medicare Subsidy 4.4 4.9 9 years Rate Case Expenses 1.2 — 2 years Deferral of Major Generation Overhauls 0.7 1.3 2 years Other Regulatory Assets Approved for Recovery 0.4 0.9 various Total Regulatory Assets Approved for Recovery 201.4 136.6 Total Noncurrent Regulatory Assets $ 214.8 $ 154.3
Regulatory Liabilities	PSO December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 76.1 $ — 1 year Total Current Regulatory Liabilities $ 76.1 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Advanced Metering Costs $ — $ 3.9 Other Regulatory Liabilities Pending Final Regulatory Determination — 0.3 Total Regulatory Liabilities Pending Final Regulatory Determination — 4.2 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 275.5 275.4 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 46.3 46.9 26 years Advanced Metering Costs 11.4 — 1 year Base Plan Funding Costs 1.3 1.4 2 years Base Load Purchase Power Contract — 6.1 Other Regulatory Liabilities Approved for Payment 0.6 0.5 various Total Regulatory Liabilities Approved for Payment 335.1 330.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 335.1 $ 334.5 (a) Relieved as removal costs are incurred.
Southwestern Electric Power Co [Member]
Regulated Generating Units to be Retired Before or During 2016	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3
Regulatory Assets	SWEPCo December 31, Remaining Recovery Period 2015 2014 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 4.1 $ 24.0 1 year Total Current Regulatory Assets $ 4.1 $ 24.0 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC $ 3.1 $ 2.3 Asset Retirement Obligation - Arkansas, Louisiana 1.7 1.1 Rate Case Expense - Texas 0.3 8.1 Other Regulatory Assets Pending Final Regulatory Approval 0.8 0.6 Total Regulatory Assets Pending Final Regulatory Approval 5.9 12.1 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Acquisition of Valley Electric Membership Corporation (VEMCO) — 1.8 Other Regulatory Assets Approved for Recovery 0.2 0.1 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 271.9 254.9 31 years Pension and OPEB Funded Status 108.9 99.9 12 years Rate Case Expense - Texas 6.8 — 3 years Unamortized Loss on Reacquired Debt 6.0 7.0 28 years Unrealized Loss on Forward Commitments 5.5 1.1 2 years Medicare Subsidy 4.8 5.3 9 years Deferred Restructuring Costs - Louisiana 3.5 5.1 3 years Peak Demand Reduction/Energy Efficiency 1.0 2.2 2 years Vegetation Management Program - Louisiana — 2.5 Other Regulatory Assets Approved for Recovery 1.3 1.6 various Total Regulatory Assets Approved for Recovery 409.9 381.5 Total Noncurrent Regulatory Assets $ 415.8 $ 393.6
Regulatory Liabilities	SWEPCo December 31, Remaining Refund Period 2015 2014 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 8.4 $ — 1 year Total Current Regulatory Liabilities $ 8.4 $ — Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 396.8 $ 384.3 (a) Refundable Construction Financing Costs - Louisiana 37.4 58.2 3 years Excess Earnings - Texas 2.7 2.8 38 years Generation Recovery Rider Costs - Arkansas 1.5 1.7 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 8.5 9.8 15 years Other Regulatory Liabilities Approved for Payment 1.9 1.7 various Total Regulatory Liabilities Approved for Payment 448.8 458.5 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 448.8 $ 458.5 (a) Relieved as removal costs are incurred.

Commitments, Guarantees and C43

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
Appalachian Power Co [Member]
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
Indiana Michigan Power Co [Member]
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
Ohio Power Co [Member]
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
Public Service Co Of Oklahoma [Member]
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
Southwestern Electric Power Co [Member]
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 2,038.0 $ 2,442.7 $ 1,723.6 $ 1,072.6 $ 7,276.9 Energy and Capacity Purchase Contracts 203.0 431.5 437.1 1,961.7 3,033.3 Construction Contracts for Capital Assets (b) 178.6 — — — 178.6 Total $ 2,419.6 $ 2,874.2 $ 2,160.7 $ 3,034.3 $ 10,488.8 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 447.4 $ 585.8 $ 486.8 $ 244.8 $ 1,764.8 Energy and Capacity Purchase Contracts 33.0 67.3 69.8 473.5 643.6 Construction Contracts for Capital Assets (b) 19.5 — — — 19.5 Total $ 499.9 $ 653.1 $ 556.6 $ 718.3 $ 2,427.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 394.2 $ 349.9 $ 252.2 $ 286.4 $ 1,282.7 Energy and Capacity Purchase Contracts 108.1 230.1 236.0 613.9 1,188.1 Construction Contracts for Capital Assets (b) 8.8 — — — 8.8 Total $ 511.1 $ 580.0 $ 488.2 $ 900.3 $ 2,479.6 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.0 $ 54.8 $ 56.2 $ 479.9 $ 617.9 Construction Contracts for Capital Assets (b) 4.7 — — — 4.7 Total $ 31.7 $ 54.8 $ 56.2 $ 479.9 $ 622.6 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 123.7 $ 86.8 $ 41.8 $ 41.8 $ 294.1 Energy and Capacity Purchase Contracts 83.6 182.2 181.9 369.7 817.4 Construction Contracts for Capital Assets (b) 1.8 — — — 1.8 Total $ 209.1 $ 269.0 $ 223.7 $ 411.5 $ 1,113.3 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 198.5 $ 136.8 $ 78.6 $ 69.8 $ 483.7 Energy and Capacity Purchase Contracts 27.3 66.0 67.7 204.6 365.6 Construction Contracts for Capital Assets (b) 4.8 — — — 4.8 Total $ 230.6 $ 202.8 $ 146.3 $ 274.4 $ 854.1 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 124.6 June 2016 to December 2016 OPCo 4.2 September 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in millions) AEP $ 476.7 $ 482.1 (a) March 2016 to July 2017 APCo 229.7 232.3 (a) March 2016 to March 2017 I&M 77.0 77.9 March 2017 (a) In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.

Dispositions and Impairments (T

Dispositions and Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3
Appalachian Power Co [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3
Indiana Michigan Power Co [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Ohio Power Co [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Public Service Co Of Oklahoma [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8
Southwestern Electric Power Co [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Plant Name and Unit Company Gross Investment Accumulated Depreciation Net Investment Materials and Supplies Cost of Removal Regulatory Liability Expected Retirement Date Remaining Recovery Period (in millions) Northeastern Station, Unit 4 PSO $ 182.5 $ 93.1 $ 89.4 $ 4.0 $ 11.3 2016 25 years Welsh Plant, Unit 2 SWEPCo 176.1 98.6 77.5 4.6 19.9 2016 25 years Total $ 358.6 $ 191.7 $ 166.9 $ 8.6 $ 31.2 December 31, 2014 Assets: (in millions) Accounts Receivable $ 90.6 Property, Plant and Equipment – Net 482.3 Other Classes of Assets That Are Not Major 52.0 Total Assets from Discontinued Operations on the Balance Sheet $ 624.9 Liabilities: Long-term Debt $ 83.2 Obligations Under Capital Leases 189.0 Other Classes of Liabilities That Are Not Major 162.6 Total Liabilities from Discontinued Operations on the Balance Sheet $ 434.8 Years Ended December 31, 2015 2014 2013 (in millions) Other Revenues $ 447.1 $ 641.6 $ 543.6 Other Operation Expense 321.3 459.5 455.7 Maintenance Expense 21.5 32.6 15.7 Depreciation and Amortization Expense 26.9 31.5 30.5 Taxes Other Than Income Taxes 10.6 14.2 10.0 Total Expenses 380.3 537.8 511.9 Other Income (Expense) (16.9 ) (17.1 ) (15.5 ) Pretax Income of Discontinued Operations 49.9 86.7 16.2 Income Tax Expense 19.4 39.0 5.9 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) — Income from Discontinued Operations of AEPRO 30.4 47.5 10.3 Gain on Sale of Discontinued Operations 240.1 — — Income Tax Expense (Benefit) (13.2 ) — — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 $ 10.3

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 5,224.9 $ 4,841.7 $ 1,439.0 $ 1,455.5 Service Cost 93.5 71.9 12.2 14.2 Interest Cost 205.3 221.0 56.8 67.2 Actuarial (Gain) Loss (200.6 ) 387.0 37.2 (14.4 ) Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Participant Contributions — — 33.3 41.9 Medicare Subsidy — — 0.8 8.3 Benefit Obligation as of December 31, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,967.5 $ 4,711.2 $ 1,693.9 $ 1,698.7 Actual Gain (Loss) on Plan Assets 32.4 474.2 (34.0 ) 82.7 Company Contributions 97.9 78.8 12.9 4.3 Participant Contributions — — 33.3 41.9 Benefit Payments (330.2 ) (296.7 ) (128.7 ) (133.7 ) Fair Value of Plan Assets as of December 31, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Funded (Underfunded) Status as of December 31, $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, AEP 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 185.8 $ 336.7 Other Current Liabilities – Accrued Short-term Benefit Liability (6.3 ) (6.2 ) (3.3 ) (3.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (219.0 ) (251.2 ) (55.7 ) (78.2 ) Funded (Underfunded) Status $ (225.3 ) $ (257.4 ) $ 126.8 $ 254.9
Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 1,546.1 $ 1,611.4 $ 577.4 $ 419.9 Prior Service Cost (Credit) 3.3 5.5 (554.4 ) (623.5 ) Recorded as Regulatory Assets $ 1,385.2 $ 1,418.3 $ 15.1 $ (148.5 ) Deferred Income Taxes 57.5 69.5 2.8 (19.3 ) Net of Tax AOCI 106.7 129.1 5.1 (35.8 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 41.8 $ 174.4 $ 176.3 $ 14.0 Amortization of Actuarial Loss (107.1 ) (124.0 ) (18.8 ) (22.1 ) Amortization of Prior Service Credit (Cost) (2.2 ) (2.5 ) 69.1 69.0 Change for the Year Ended December 31, $ (67.5 ) $ 47.9 $ 226.6 $ 60.9
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 93.5 $ 71.9 $ 69.2 $ 12.2 $ 14.2 $ 22.9 Interest Cost 205.3 221.0 202.8 56.8 67.2 70.8 Expected Return on Plan Assets (274.8 ) (261.6 ) (277.8 ) (111.0 ) (111.3 ) (106.6 ) Amortization of Prior Service Cost (Credit) 2.2 2.5 2.8 (69.1 ) (69.0 ) (69.0 ) Amortization of Net Actuarial Loss 107.1 124.0 183.1 18.8 22.1 64.7 Net Periodic Benefit Cost (Credit) 133.3 157.8 180.1 (92.3 ) (76.8 ) (17.2 ) Capitalized Portion (48.4 ) (52.2 ) (56.4 ) 33.5 25.3 5.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 84.9 $ 105.6 $ 123.7 $ (58.8 ) $ (51.5 ) $ (11.8 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Appalachian Power Co [Member]
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 702.8 $ 663.2 $ 267.1 $ 279.9 Service Cost 8.7 7.0 1.1 1.4 Interest Cost 26.7 29.6 10.3 12.8 Actuarial (Gain) Loss (41.4 ) 41.7 2.5 (9.0 ) Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Participant Contributions — — 5.7 7.2 Medicare Subsidy — — 0.2 1.4 Benefit Obligation as of December 31, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 642.3 $ 628.0 $ 280.6 $ 284.8 Actual Gain (Loss) on Plan Assets (5.7 ) 44.0 (7.7 ) 11.8 Company Contributions 10.0 9.0 2.8 3.4 Participant Contributions — — 5.7 7.2 Benefit Payments (43.4 ) (38.7 ) (24.7 ) (26.6 ) Fair Value of Plan Assets as of December 31, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Funded (Underfunded) Status as of December 31, $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, APCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 30.8 $ 56.5 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.6 ) (2.9 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (50.2 ) (60.5 ) (33.7 ) (40.1 ) Funded (Underfunded) Status $ (50.2 ) $ (60.5 ) $ (5.5 ) $ 13.5
Amounts Included in AOCI and Regulatory Assets	APCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 220.8 $ 235.0 $ 86.9 $ 65.8 Prior Service Cost (Credit) 0.3 0.5 (80.6 ) (90.6 ) Recorded as Regulatory Assets $ 218.3 $ 232.8 $ (0.7 ) $ (20.3 ) Deferred Income Taxes 1.0 0.9 2.4 (1.6 ) Net of Tax AOCI 1.8 1.8 4.6 (2.9 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	APCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (0.3 ) $ 31.6 $ 24.7 $ (2.3 ) Amortization of Actuarial Loss (13.9 ) (16.6 ) (3.6 ) (4.6 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 10.0 10.1 Change for the Year Ended December 31, $ (14.4 ) $ 14.8 $ 31.1 $ 3.2
Allocated Assets of Investments	Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.7 $ 7.0 $ 6.2 $ 1.1 $ 1.4 $ 2.6 Interest Cost 26.7 29.6 27.7 10.3 12.8 13.5 Expected Return on Plan Assets (35.0 ) (33.9 ) (37.1 ) (18.1 ) (18.5 ) (18.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (10.0 ) (10.1 ) (10.1 ) Amortization of Net Actuarial Loss 13.9 16.6 25.0 3.6 4.6 12.2 Net Periodic Benefit Cost (Credit) 14.5 19.5 22.0 (13.1 ) (9.8 ) 0.1 Capitalized Portion (5.5 ) (6.8 ) (7.5 ) 5.0 3.4 (0.1 ) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 9.0 $ 12.7 $ 14.5 $ (8.1 ) $ (6.4 ) $ —
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Indiana Michigan Power Co [Member]
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 617.9 $ 574.7 $ 161.7 $ 166.5 Service Cost 12.9 10.0 1.6 1.9 Interest Cost 24.5 26.3 6.4 7.6 Actuarial (Gain) Loss (28.4 ) 38.5 7.7 (4.9 ) Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Participant Contributions — — 4.0 5.2 Medicare Subsidy — — 0.1 1.1 Benefit Obligation as of December 31, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 591.7 $ 559.1 $ 202.4 $ 206.2 Actual Gain (Loss) on Plan Assets (0.9 ) 55.3 (2.3 ) 6.6 Company Contributions 14.6 8.9 0.1 0.1 Participant Contributions — — 4.0 5.2 Benefit Payments (35.4 ) (31.6 ) (15.2 ) (15.7 ) Fair Value of Plan Assets as of December 31, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Funded (Underfunded) Status as of December 31, $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, I&M 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 22.7 $ 40.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (21.5 ) (26.2 ) — — Funded (Underfunded) Status $ (21.5 ) $ (26.2 ) $ 22.7 $ 40.7
Amounts Included in AOCI and Regulatory Assets	I&M Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 130.0 $ 137.9 $ 77.1 $ 54.4 Prior Service Cost (Credit) 0.3 0.5 (75.7 ) (85.1 ) Recorded as Regulatory Assets $ 125.3 $ 134.1 $ 1.1 $ (26.3 ) Deferred Income Taxes 1.8 1.5 0.1 (1.5 ) Net of Tax AOCI 3.2 2.8 0.2 (2.9 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	I&M Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 4.7 $ 14.2 $ 24.7 $ 1.9 Amortization of Actuarial Loss (12.6 ) (14.6 ) (2.0 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ (8.1 ) $ (0.6 ) $ 32.1 $ 8.9
Allocated Assets of Investments	Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	I&M Pension Plans Other Postretirement Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 12.9 $ 10.0 $ 8.7 $ 1.6 $ 1.9 $ 3.2 Interest Cost 24.5 26.3 24.1 6.4 7.6 8.2 Expected Return on Plan Assets (32.6 ) (31.0 ) (32.8 ) (13.2 ) (13.4 ) (13.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (9.4 ) (9.4 ) (9.4 ) Amortization of Net Actuarial Loss 12.6 14.6 21.7 2.0 2.4 7.5 Net Periodic Benefit Cost (Credit) 17.6 20.1 21.9 (12.6 ) (10.9 ) (3.7 ) Capitalized Portion (4.0 ) (4.6 ) (4.6 ) 2.9 2.5 0.8 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 13.6 $ 15.5 $ 17.3 $ (9.7 ) $ (8.4 ) $ (2.9 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Ohio Power Co [Member]
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 526.3 $ 523.6 $ 164.7 $ 171.2 Service Cost 6.7 5.2 0.9 1.0 Interest Cost 20.3 22.1 6.4 7.6 Actuarial (Gain) Loss (19.5 ) 6.8 8.7 (4.3 ) Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Participant Contributions — — 4.3 5.6 Medicare Subsidy — — (0.1 ) 1.0 Benefit Obligation as of December 31, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 498.5 $ 501.6 $ 206.2 $ 212.0 Actual Gain (Loss) on Plan Assets 2.2 21.7 (2.6 ) 6.0 Company Contributions 7.7 6.6 — — Participant Contributions — — 4.3 5.6 Benefit Payments (36.3 ) (31.4 ) (16.3 ) (17.4 ) Fair Value of Plan Assets as of December 31, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Funded (Underfunded) Status as of December 31, $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 23.0 $ 41.5 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (25.4 ) (27.8 ) — — Funded (Underfunded) Status $ (25.4 ) $ (27.8 ) $ 23.0 $ 41.5
Amounts Included in AOCI and Regulatory Assets	OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 222.0 $ 226.7 $ 52.6 $ 30.7 Prior Service Cost (Credit) 0.2 0.4 (55.4 ) (62.4 ) Recorded as Regulatory Assets $ 222.2 $ 227.1 $ (2.8 ) $ (31.7 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	OPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial Loss During the Year $ 5.8 $ 11.5 $ 24.0 $ 3.3 Amortization of Actuarial Loss (10.5 ) (12.4 ) (2.1 ) (2.4 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.2 ) 7.0 6.9 Change for the Year Ended December 31, $ (4.9 ) $ (1.1 ) $ 28.9 $ 7.8
Allocated Assets of Investments	Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	OPCo Pension Plans Other Postretirement Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 6.7 $ 5.2 $ 5.3 $ 0.9 $ 1.0 $ 2.9 Interest Cost 20.3 22.1 21.9 6.4 7.6 9.5 Expected Return on Plan Assets (27.5 ) (26.5 ) (29.9 ) (13.4 ) (13.5 ) (13.5 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 0.2 (7.0 ) (6.9 ) (6.9 ) Amortization of Net Actuarial Loss 10.5 12.4 19.8 2.1 2.4 8.6 Net Periodic Benefit Cost (Credit) 10.2 13.4 17.3 (11.0 ) (9.4 ) 0.6 Capitalized Portion (4.8 ) (5.5 ) (6.2 ) 5.2 3.8 (0.2 ) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 5.4 $ 7.9 $ 11.1 $ (5.8 ) $ (5.6 ) $ 0.4
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Public Service Co Of Oklahoma [Member]
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 285.4 $ 260.7 $ 76.7 $ 77.8 Service Cost 6.4 5.2 0.7 0.8 Interest Cost 10.9 12.1 3.0 3.6 Actuarial (Gain) Loss (17.9 ) 25.7 2.4 (1.0 ) Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Participant Contributions — — 1.9 2.3 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 275.5 $ 264.6 $ 96.0 $ 96.3 Actual Gain (Loss) on Plan Assets 0.1 24.6 (2.5 ) 4.7 Company Contributions 5.9 4.6 — — Participant Contributions — — 1.9 2.3 Benefit Payments (19.4 ) (18.3 ) (7.1 ) (7.3 ) Fair Value of Plan Assets as of December 31, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Funded (Underfunded) Status as of December 31, $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, PSO 2015 2014 2015 2014 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ — $ — $ 10.6 $ 19.3 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (3.1 ) (9.7 ) — — Funded (Underfunded) Status $ (3.3 ) $ (9.9 ) $ 10.6 $ 19.3
Amounts Included in AOCI and Regulatory Assets	PSO Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 94.1 $ 102.7 $ 35.2 $ 25.3 Prior Service Cost (Credit) 0.3 0.5 (34.5 ) (38.8 ) Recorded as Regulatory Assets $ 94.4 $ 103.2 $ 0.7 $ (13.5 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	PSO Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (2.9 ) $ 15.7 $ 10.9 $ 0.6 Amortization of Actuarial Loss (5.7 ) (6.7 ) (1.0 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.2 ) (0.3 ) 4.3 4.3 Change for the Year Ended December 31, $ (8.8 ) $ 8.7 $ 14.2 $ 3.8
Allocated Assets of Investments	Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	PSO Pension Plans Other Postretirement Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 6.4 $ 5.2 $ 5.6 $ 0.7 $ 0.8 $ 1.4 Interest Cost 10.9 12.1 11.0 3.0 3.6 3.8 Expected Return on Plan Assets (15.1 ) (14.6 ) (15.7 ) (6.3 ) (6.3 ) (6.1 ) Amortization of Prior Service Cost (Credit) 0.2 0.3 0.3 (4.3 ) (4.3 ) (4.3 ) Amortization of Net Actuarial Loss 5.7 6.7 9.8 1.0 1.1 3.5 Net Periodic Benefit Cost (Credit) 8.1 9.7 11.0 (5.9 ) (5.1 ) (1.7 ) Capitalized Portion (2.8 ) (3.3 ) (3.4 ) 2.0 1.7 0.5 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 5.3 $ 6.4 $ 7.6 $ (3.9 ) $ (3.4 ) $ (1.2 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Southwestern Electric Power Co [Member]
Health Care Trend Rates	Health Care Trend Rates 2015 2014 Initial 6.25 % 6.50 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2020 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.7 $ 0.8 $ 0.3 $ 0.3 $ 0.1 $ 0.2 1% Decrease (3.0 ) (0.6 ) (0.3 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 70.5 $ 15.2 $ 6.8 $ 6.9 $ 3.2 $ 3.5 1% Decrease (57.4 ) (12.3 ) (5.6 ) (5.7 ) (2.6 ) (2.9 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 298.2 $ 270.6 $ 85.0 $ 87.0 Service Cost 8.3 6.6 0.8 1.0 Interest Cost 11.8 12.7 3.4 4.0 Actuarial (Gain) Loss (16.2 ) 27.5 2.1 (2.3 ) Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Participant Contributions — — 2.1 2.5 Medicare Subsidy — — 0.1 0.5 Benefit Obligation as of December 31, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 290.2 $ 279.0 $ 106.4 $ 107.7 Actual Gain (Loss) on Plan Assets 1.6 26.5 (3.3 ) 3.9 Company Contributions 8.1 3.9 — — Participant Contributions — — 2.1 2.5 Benefit Payments (19.3 ) (19.2 ) (7.4 ) (7.7 ) Fair Value of Plan Assets as of December 31, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Funded (Underfunded) Status as of December 31, $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2015 2014 2015 2014 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 11.7 $ 21.4 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (7.9 ) — — Funded (Underfunded) Status $ (2.2 ) $ (8.0 ) $ 11.7 $ 21.4
Amounts Included in AOCI and Regulatory Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2015 2014 2015 2014 Components (in millions) Net Actuarial Loss $ 97.1 $ 104.9 $ 43.3 $ 32.4 Prior Service Cost (Credit) 0.4 0.7 (41.6 ) (46.8 ) Recorded as Regulatory Assets $ 97.5 $ 105.6 $ 1.2 $ (8.9 ) Deferred Income Taxes — — 0.2 (1.9 ) Net of Tax AOCI — — 0.3 (3.6 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans 2015 2014 2015 2014 Components (in millions) Actuarial (Gain) Loss During the Year $ (1.8 ) $ 16.5 $ 12.0 $ 0.8 Amortization of Actuarial Loss (6.0 ) (7.1 ) (1.1 ) (1.2 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.2 5.2 Change for the Year Ended December 31, $ (8.1 ) $ 9.1 $ 16.1 $ 4.8
Allocated Assets of Investments	Pension Plan Other Postretirement Company 2015 2014 2015 2014 APCo 12.7 % 12.9 % 16.3 % 16.6 % I&M 12.0 % 11.9 % 12.0 % 11.9 % OPCo 9.9 % 10.0 % 12.1 % 12.2 % PSO 5.5 % 5.5 % 5.6 % 5.7 % SWEPCo 5.9 % 5.8 % 6.2 % 6.3 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,982.0 $ 688.6 $ 598.2 $ 512.4 $ 270.0 $ 281.2 Nonqualified Pension Plans 76.0 0.5 0.5 0.1 2.8 1.8 Total as of December 31, 2014 $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 272.8 $ 283.0
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,224.9 $ 702.8 $ 617.9 $ 526.3 $ 2.8 $ 1.8 Accumulated Benefit Obligation $ 5,058.0 $ 689.1 $ 598.7 $ 512.5 $ 2.8 $ 1.8 Fair Value of Plan Assets 4,967.5 642.3 591.7 498.5 — — Underfunded Accumulated Benefit Obligation as of December 31, 2014 $ (90.5 ) $ (46.8 ) $ (7.0 ) $ (14.0 ) $ (2.8 ) $ (1.8 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 95.6 $ 6.0 APCo 10.7 2.6 I&M 13.1 — OPCo 7.5 — PSO 5.7 — SWEPCo 6.9 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 324.0 $ 42.8 $ 33.9 $ 36.4 $ 19.3 $ 18.6 2017 335.5 43.2 35.6 36.0 20.2 20.2 2018 339.3 44.2 36.0 35.8 20.1 21.1 2019 348.7 44.6 38.6 36.1 20.9 21.8 2020 355.9 45.0 39.3 36.2 21.3 22.4 Years 2021 to 2025, in Total 1,844.3 232.3 213.1 174.3 109.1 120.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 134.1 $ 25.3 $ 15.9 $ 16.9 $ 7.4 $ 7.9 2017 136.7 25.4 16.2 17.1 7.6 8.1 2018 139.1 25.6 16.6 17.3 7.7 8.3 2019 140.3 25.3 16.8 17.3 7.9 8.4 2020 143.6 25.6 17.2 17.5 8.1 8.7 Years 2021 to 2025, in Total 749.7 127.9 90.4 87.6 42.7 47.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 0.3 $ 0.2 $ — $ — $ — $ — 2017 0.3 0.2 — — — — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — Years 2021 to 2025, in Total 1.8 1.1 — — — —
Components of Net Periodic Benefit Cost	SWEPCo Pension Plans Other Postretirement Years Ended December 31, 2015 2014 2013 2015 2014 2013 (in millions) Service Cost $ 8.3 $ 6.6 $ 7.0 $ 0.8 $ 1.0 $ 1.7 Interest Cost 11.8 12.7 11.5 3.4 4.0 4.3 Expected Return on Plan Assets (16.0 ) (15.4 ) (16.5 ) (6.9 ) (7.0 ) (6.9 ) Amortization of Prior Service Cost (Credit) 0.3 0.3 0.3 (5.2 ) (5.2 ) (5.1 ) Amortization of Net Actuarial Loss 6.0 7.1 10.2 1.1 1.2 3.9 Net Periodic Benefit Cost (Credit) 10.4 11.3 12.5 (6.8 ) (6.0 ) (2.1 ) Capitalized Portion (3.2 ) (3.4 ) (3.5 ) 2.1 1.8 0.6 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 7.2 $ 7.9 $ 9.0 $ (4.7 ) $ (4.2 ) $ (1.5 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 82.9 $ 10.7 $ 9.7 $ 8.2 $ 4.4 $ 4.7 Prior Service Cost 2.2 0.2 0.2 0.1 0.2 0.3 Total Estimated 2016 Amortization $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 Pension Plans – Expected to be Recorded as Regulatory Asset $ 73.8 $ 10.9 $ 9.3 $ 8.3 $ 4.6 $ 5.0 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.4 — 0.4 — — — Total $ 85.1 $ 10.9 $ 9.9 $ 8.3 $ 4.6 $ 5.0 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 29.8 $ 5.2 $ 3.5 $ 3.6 $ 1.7 $ 1.8 Prior Service Credit (69.0 ) (10.1 ) (9.4 ) (6.9 ) (4.3 ) (5.1 ) Total Estimated 2016 Amortization $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (28.5 ) $ (2.6 ) $ (5.3 ) $ (3.3 ) $ (2.6 ) $ (2.1 ) Deferred Income Taxes (3.7 ) (0.8 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (7.0 ) (1.5 ) (0.4 ) — — (0.8 ) Total $ (39.2 ) $ (4.9 ) $ (5.9 ) $ (3.3 ) $ (2.6 ) $ (3.3 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 73.6 $ 70.5 $ 66.6 APCo 7.2 7.3 7.4 I&M 10.6 10.5 10.0 OPCo 5.4 5.2 6.5 PSO 4.2 4.0 3.8 SWEPCo 5.7 5.3 5.0
Pension Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 588.6 $ — $ — $ — $ 588.6 11.9 % International 502.2 — — — 502.2 10.1 % Options — 14.1 — — 14.1 0.3 % Real Estate Investment Trusts 54.3 — — — 54.3 1.1 % Common Collective Trust – Global — 377.0 — — 377.0 7.6 % Common Collective Trust – International — 18.5 — — 18.5 0.4 % Subtotal – Equities 1,145.1 409.6 — — 1,554.7 31.4 % Fixed Income: Common Collective Trust – Debt — 30.2 — — 30.2 0.6 % United States Government and Agency Securities — 449.8 — — 449.8 9.0 % Corporate Debt — 1,799.5 — — 1,799.5 36.2 % Foreign Debt — 400.5 0.1 — 400.6 8.1 % State and Local Government — 14.9 — — 14.9 0.3 % Other – Asset Backed — 29.1 — — 29.1 0.6 % Subtotal – Fixed Income — 2,724.0 0.1 — 2,724.1 54.8 % Infrastructure — — 12.5 — 12.5 0.3 % Real Estate — — 235.8 — 235.8 4.7 % Alternative Investments — — 378.9 — 378.9 7.6 % Securities Lending — 219.8 — — 219.8 4.4 % Securities Lending Collateral (a) — — — (221.5 ) (221.5 ) (4.5 )% Cash and Cash Equivalents — 53.3 — — 53.3 1.1 % Other – Pending Transactions and Accrued Income (b) — — — 9.9 9.9 0.2 % Total $ 1,145.1 $ 3,406.7 $ 627.3 $ (211.6 ) $ 4,967.5 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trust – Global — 369.7 — — 369.7 7.8 % Common Collective Trust – International — 16.1 — — 16.1 0.3 % Subtotal – Equities 722.0 401.4 — — 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt — 34.2 — — 34.2 0.7 % United States Government and Agency Securities — 421.9 — — 421.9 8.9 % Corporate Debt — 1,983.2 — — 1,983.2 41.6 % Foreign Debt — 421.4 0.1 — 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed — 23.4 — — 23.4 0.5 % Subtotal – Fixed Income — 2,896.9 0.1 — 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents — 48.6 — — 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,609.9 $ 674.5 $ (238.8 ) $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Pension Plan Assets Level 3 Reconciliation	Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2014 $ 0.1 $ — $ 238.2 $ 329.6 $ 567.9 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (0.3 ) 5.5 32.0 37.2 Relating to Assets Sold During the Period — 0.1 19.0 15.8 34.9 Purchases and Sales — 12.7 (26.9 ) 1.5 (12.7 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2014 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5
Other Postretirement Benefit Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trust – Global — 19.0 — — 19.0 1.2 % Common Collective Trust – International — 12.6 — — 12.6 0.8 % Subtotal – Equities 949.4 47.2 — — 996.6 63.2 % Fixed Income: Common Collective Trust – Debt — 100.9 — — 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 310.3 — — 310.3 19.6 % Trust Owned Life Insurance: International Equities — 28.3 — — 28.3 1.8 % United States Bonds — 184.3 — — 184.3 11.7 % Subtotal – Trust Owned Life Insurance — 212.6 — — 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 577.3 $ — $ 5.8 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 466.1 $ — $ — $ — $ 466.1 27.5 % International 566.6 — — — 566.6 33.5 % Options — 16.4 — — 16.4 1.0 % Common Collective Trust – Global — 29.6 — — 29.6 1.8 % Subtotal – Equities 1,032.7 46.0 — — 1,078.7 63.8 % Fixed Income: Common Collective Trust – Debt — 103.7 — — 103.7 6.1 % United States Government and Agency Securities — 71.1 — — 71.1 4.2 % Corporate Debt — 125.5 — — 125.5 7.4 % Foreign Debt — 21.3 — — 21.3 1.3 % State and Local Government — 5.9 — — 5.9 0.3 % Other – Asset Backed — 4.9 — — 4.9 0.3 % Subtotal – Fixed Income — 332.4 — — 332.4 19.6 % Trust Owned Life Insurance: International Equities — 10.3 — — 10.3 0.6 % United States Bonds — 212.1 — — 212.1 12.5 % Subtotal – Trust Owned Life Insurance — 222.4 — — 222.4 13.1 % Cash and Cash Equivalents 46.8 9.6 — — 56.4 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 4.0 4.0 0.2 % Total $ 1,079.5 $ 610.4 $ — $ 4.0 $ 1,693.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Obligations [Member] | Appalachian Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Obligations [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Obligations [Member] | Ohio Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Obligations [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Obligations [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumption 2015 2014 2015 2014 Discount Rate 4.30 % 4.00 % 4.30 % 4.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 AEP 4.80 % 4.80 % APCo 4.45 % 4.45 % I&M 4.75 % 4.80 % OPCo 4.85 % 4.80 % PSO 4.85 % 4.80 % SWEPCo 4.80 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member] | Appalachian Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member] | Ohio Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans Assumptions 2015 2014 2013 2015 2014 2013 Discount Rate 4.00 % 4.70 % 3.95 % 4.00 % 4.70 % 3.95 % Expected Return on Plan Assets 6.00 % 6.00 % 6.50 % 6.75 % 6.75 % 7.00 % Pension Plans Assumption – Rate of Compensation Increase (a) 2015 2014 2013 AEP 4.80 % 4.85 % 4.95 % APCo 4.45 % 4.60 % 4.70 % I&M 4.80 % 4.90 % 5.00 % OPCo 4.80 % 5.00 % 5.00 % PSO 4.80 % 4.90 % 4.90 % SWEPCo 4.80 % 4.85 % 4.75 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.2 $ 43.0 $ 201.4 $ 1.0 $ 15.5 (d) 2,009.7 Interest and Investment Income 4.6 6.1 0.2 2.8 9.5 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 275.8 37.2 40.0 30.7 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ (42.0 ) $ — 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 351.7 $ 192.7 $ 366.0 $ 241.7 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.3 $ 1,121.3 $ 134.3 $ 4.9 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees 31.9 0.9 630.8 0.1 56.8 — 720.5 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 935.4 824.7 — 71.6 0.1 — 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 11.4 — 4.7 7.3 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 279.9 23.5 45.3 25.5 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.1 62.9 179.3 15.8 — 902.6 Income from Continuing Operations $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 5.9 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 354.6 $ 150.8 $ 367.4 $ 53.4 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Property, Plant and Equipment $ 39,402.4 $ 13,023.8 $ 2,714.2 $ 8,394.3 $ 342.7 $ (271.5 ) (d) $ 63,605.9 Accumulated Depreciation and Amortization 12,772.8 3,480.7 24.5 3,602.9 188.1 (98.2 ) (d) 19,970.8 Total Property, Plant and Equipment – Net $ 26,629.6 $ 9,543.1 $ 2,689.7 $ 4,791.4 $ 154.6 $ (173.3 ) (d) $ 43,635.1 Assets from Discontinued Operations $ — $ — $ — $ — $ 624.9 $ — $ 624.9 Total Assets 33,705.1 14,463.4 3,570.0 6,326.2 21,826.5 (20,346.6 ) (d) (e) 59,544.6 Investments in Equity Method Investees 26.2 1.1 548.0 0.1 73.0 — 648.4 Long-term Debt Due Within One Year: Affiliated $ 111.0 $ — $ — $ 86.0 $ — $ (197.0 ) $ — Non-Affiliated 1,352.4 405.2 — 740.0 2.8 — 2,500.4 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 8,589.2 5,224.2 1,147.5 214.8 836.3 — 16,012.0 Total Long-term Debt $ 10,072.6 $ 5,629.4 $ 1,147.5 $ 1,073.0 $ 839.1 $ (249.2 ) $ 18,512.4 Liabilities from Discontinued Operations $ — $ — $ — $ — $ 434.8 $ — $ 434.8 (f) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2013 Revenues from: External Customers $ 9,346.6 $ 4,279.1 $ 26.8 $ 1,208.0 $ 32.5 $ (79.5 ) (c) $ 14,813.5 Other Operating Segments 645.9 199.3 50.9 2,457.2 56.3 (3,409.6 ) — Total Revenues $ 9,992.5 $ 4,478.4 $ 77.7 $ 3,665.2 $ 88.8 $ (3,489.1 ) $ 14,813.5 Asset Impairments and Other Related Charges $ 72.1 $ — $ — $ 154.3 $ — $ — $ 226.4 Depreciation and Amortization 941.5 591.3 10.1 236.1 0.3 (66.8 ) (d) 1,712.5 Interest and Investment Income 7.2 1.6 — 2.1 68.8 (21.8 ) 57.9 Carrying Costs Income 13.8 16.3 0.1 — — — 30.2 Interest Expense 540.1 291.0 10.0 55.5 26.9 (33.5 ) (d) 890.0 Income Tax Expense (Credit) 398.1 198.3 29.0 112.2 (59.9 ) — 677.7 Income from Continuing Operations $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 127.1 $ — $ 1,473.9 Income from Discontinued Operations, Net of Tax — — — — 10.3 — 10.3 Net Income $ 681.7 $ 357.8 $ 79.4 $ 227.9 $ 137.4 $ — $ 1,484.2 Gross Property Additions $ 1,822.0 $ 870.9 $ 842.6 $ 185.2 $ 9.1 $ (81.4 ) $ 3,648.4 Total Assets 32,745.5 14,127.3 2,241.5 6,424.0 20,312.9 (19,530.2 ) (d) (e) 56,321.0 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) 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. (f) Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	12 Months Ended
	Dec. 31, 2015
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 AEP Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 392.6 $ 30.0 $ 2.6 $ 425.2 $ (247.3 ) $ 177.9 Long-term Risk Management Assets 366.7 3.8 — 370.5 (76.3 ) 294.2 Total Assets 759.3 33.8 2.6 795.7 (323.6 ) 472.1 Current Risk Management Liabilities 328.6 23.4 0.7 352.7 (261.1 ) 91.6 Long-term Risk Management Liabilities 208.0 7.9 9.2 225.1 (94.2 ) 130.9 Total Liabilities 536.6 31.3 9.9 577.8 (355.3 ) 222.5 Total MTM Derivative Contract Net Assets (Liabilities) $ 222.7 $ 2.5 $ (7.3 ) $ 217.9 $ 31.7 $ 249.6 (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 primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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	Years Ended December 31, 2015 2014 2013 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 3.2 $ 3.8 $ (10.4 ) Gain (Loss) on Fair Value Portion of Long-term Debt (3.3 ) (3.9 ) 10.4
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —
Appalachian Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ — $ — $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Assets 26.2 — — 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 — — 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 — — 0.3 (0.2 ) 0.1 Total Liabilities 18.4 — — 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 7.8 $ — $ — $ 7.8 $ 3.0 $ 10.8 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 32.9 $ — $ — $ 32.9 $ (9.1 ) $ 23.8 Long-term Risk Management Assets - Nonaffiliated 5.2 — — 5.2 (0.3 ) 4.9 Total Assets 38.1 — — 38.1 (9.4 ) 28.7 Current Risk Management Liabilities - Nonaffiliated 20.2 — — 20.2 (9.2 ) 11.0 Long-term Risk Management Liabilities - Nonaffiliated 2.3 — — 2.3 (0.2 ) 2.1 Total Liabilities 22.5 — — 22.5 (9.4 ) 13.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.6 $ — $ — $ 15.6 $ — $ 15.6 (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 Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —
Indiana Michigan Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	I&M Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ — $ — $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 — — 0.6 (0.6 ) — Total Assets 23.4 — — 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 — — 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 — — 2.6 (1.0 ) 1.6 Total Liabilities 19.6 — — 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 3.8 $ — $ — $ 3.8 $ 0.6 $ 4.4 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets - Nonaffiliated $ 28.5 $ — $ — $ 28.5 $ (6.2 ) $ 22.3 Long-term Risk Management Assets - Nonaffiliated 3.5 — — 3.5 (0.2 ) 3.3 Total Assets 32.0 — — 32.0 (6.4 ) 25.6 Current Risk Management Liabilities - Nonaffiliated 11.3 — — 11.3 (6.1 ) 5.2 Long-term Risk Management Liabilities - Nonaffiliated 1.6 — — 1.6 (0.2 ) 1.4 Total Liabilities 12.9 — — 12.9 (6.3 ) 6.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 19.1 $ — $ — $ 19.1 $ (0.1 ) $ 19.0 (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 Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —
Ohio Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 19.2 — — 19.2 — 19.2 Total Assets 19.2 — — 19.2 — 19.2 Current Risk Management Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — — — — Total Liabilities 4.1 — — 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 15.1 $ — $ — $ 15.1 $ 0.5 $ 15.6 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 7.2 $ — $ — $ 7.2 $ — $ 7.2 Long-term Risk Management Assets 45.1 — — 45.1 — 45.1 Total Assets 52.3 — — 52.3 — 52.3 Current Risk Management Liabilities 2.0 — — 2.0 (0.1 ) 1.9 Long-term Risk Management Liabilities 3.0 — — 3.0 — 3.0 Total Liabilities 5.0 — — 5.0 (0.1 ) 4.9 Total MTM Derivative Contract Net Assets (Liabilities) $ 47.3 $ — $ — $ 47.3 $ 0.1 $ 47.4 (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 Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.6 $ — $ — $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — — — — Total Assets 0.6 — — 0.6 — 0.6 Current Risk Management Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — — — — Total Liabilities 0.5 — — 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.1 $ — $ — $ 0.1 $ 0.3 $ 0.4 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.4 $ — $ — $ 0.4 $ (0.4 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.4 — — 0.4 (0.4 ) — Current Risk Management Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.3 — — 1.3 (0.4 ) 0.9 Total MTM Derivative Contract Net Assets (Liabilities) $ (0.9 ) $ — $ — $ (0.9 ) $ — $ (0.9 ) (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 Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2015 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 317.8 40.9 22.8 13.3 11.3 14.0 Coal Tons 4.4 — 1.6 — — 2.8 Natural Gas MMBtus 38.2 0.3 0.2 — 0.2 0.2 Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 113.5 $ 2.4 $ 1.6 $ — $ — $ — Interest Rate and Foreign Currency USD $ 560.3 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 333.7 32.5 23.8 20.3 16.8 20.5 Coal Tons 3.1 0.3 0.5 — — 1.5 Natural Gas MMBtus 105.9 0.4 0.3 — — — Heating Oil and Gasoline Gallons 5.5 1.1 0.5 1.1 0.6 0.7 Interest Rate USD $ 152.0 $ 5.1 $ 3.5 $ — $ — $ — Interest Rate and Foreign Currency USD $ 815.2 $ — $ — $ — $ — $ —
Cash Collateral Netting	December 31, 2015 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 5.8 $ 44.4 $ 3.5 $ 35.2 APCo — 3.1 0.1 0.1 I&M — 0.6 0.2 — OPCo — 0.5 — 0.1 PSO — 0.3 — 0.1 SWEPCo — 0.3 — 0.1
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.8 $ — $ — $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — — — — Total Assets 0.8 — — 0.8 — 0.8 Current Risk Management Liabilities 3.4 — — 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — — 2.1 — 2.1 Total Liabilities 5.5 — — 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ — $ — $ (4.7 ) $ 0.3 $ (4.4 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 0.5 $ — $ — $ 0.5 $ (0.5 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 0.5 — — 0.5 (0.5 ) — Current Risk Management Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1.6 — — 1.6 (0.5 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ (1.1 ) $ — $ — $ (1.1 ) $ — $ (1.1 ) (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 Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2013 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 15.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 49.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 2.0 10.6 4.9 0.4 0.6 Regulatory Assets (a) (2.4 ) — — (5.8 ) 2.9 0.4 Regulatory Liabilities (a) (5.0 ) (0.3 ) (9.1 ) 2.9 1.0 1.5 Total Gain on Risk Management Contracts $ 56.9 $ 1.7 $ 1.5 $ 2.0 $ 4.3 $ 2.5 (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 Balance Sheet	Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 17.6 $ — $ 26.1 $ 0.4 $ (5.2 ) $ (17.2 ) APCo — — — — — 3.6 I&M — — — — — (13.3 ) OPCo — — — — — 4.3 PSO — — — — — 4.2 SWEPCo — — — — — (9.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in millions) (in months) AEP $ (0.4 ) $ (1.5 ) 144 APCo — 0.7 0 I&M — (1.3 ) 0 OPCo — 1.2 0 PSO — 0.8 0 SWEPCo — (1.7 ) 0 Impact of Cash Flow Hedges on the Registrants’ Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in millions) AEP $ 16.8 $ — $ 14.3 $ 1.0 $ 1.6 $ (19.1 ) APCo — — — — — 3.9 I&M — — — — — (14.4 ) OPCo — — — — — 5.6 PSO — — — — — 5.0 SWEPCo — — — — — (11.1 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency (in millions) AEP $ 4.3 $ (2.0 ) APCo — 0.3 I&M — (1.1 ) OPCo — 1.4 PSO — 0.8 SWEPCo — (2.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	December 31, 2015 Company Fair Value of Contracts with Credit Downgrade Triggers Amount of Collateral the Registrants Would Have Been Required to Post for Derivative Contracts as well as Non- Derivative Contracts Subject to the Same Master Netting Arrangement Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs Amount of Collateral Attributable to Other Contracts (in millions) AEP $ — $ — $ 17.5 $ 297.8 (a) APCo — — 4.9 0.1 I&M — — 3.3 0.1 OPCo — — — — PSO — — — 3.2 SWEPCo — — — 0.1 December 31, 2014 Company Fair Value Amount of Collateral Amount of Collateral Amount of (in millions) AEP $ — $ — $ 36.0 $ 280.6 (a) APCo — — 6.3 0.1 I&M — — 4.3 — OPCo — — — — PSO — — 0.7 4.1 SWEPCo — — 0.9 0.2 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 235.2 $ 8.5 $ 178.2 APCo 9.0 — 9.0 I&M 6.1 — 6.1 OPCo — — — PSO — — — SWEPCo — — —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information. (b) Amount excludes $114 million of fair value of Long-term Debt related to AEPRO.
Other Temporary Investments	December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds 91.1 — (0.7 ) 90.4 Equity Securities – Mutual Funds 13.7 11.7 — 25.4 Total Other Temporary Investments $ 375.8 $ 11.7 $ (0.7 ) $ 386.8 December 31, 2014 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 279.7 $ — $ — $ 279.7 Fixed Income Securities – Mutual Funds 80.5 — — 80.5 Equity Securities – Mutual Funds 13.1 12.3 — 25.4 Total Other Temporary Investments $ 373.3 $ 12.3 $ — $ 385.6 (a) Primarily represents amounts held for the repayment of debt.
Debt and Equity Securities Within Other Temporary Investments	Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 10.7 1.6 17.4 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — —
Nuclear Trust Fund Investments	December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 )
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2
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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.9 $ 4.3 $ — $ 168.2 $ 176.4 Other Temporary Investments Restricted Cash (a) 230.0 7.7 — 33.3 271.0 Fixed Income Securities – Mutual Funds 90.4 — — — 90.4 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 345.8 7.7 — 33.3 386.8 Risk Management Assets Risk Management Commodity Contracts (c) (d) 11.5 495.0 219.7 (287.7 ) 438.5 Cash Flow Hedges: Commodity Hedges (c) — 15.9 1.0 0.7 17.6 Fair Value Hedges — — — 0.1 0.1 Total Risk Management Assets 11.5 510.9 220.7 (286.9 ) 456.2 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,648.6 $ 1,334.1 $ 220.7 $ (77.6 ) $ 3,125.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 24.1 $ 471.5 $ 67.3 $ (326.3 ) $ 236.6 Cash Flow Hedges: Commodity Hedges (c) — 18.9 6.5 0.7 26.1 Interest Rate/Foreign Currency Hedges — 0.4 — — 0.4 Fair Value Hedges — 3.0 — 0.1 3.1 Total Risk Management Liabilities $ 24.1 $ 493.8 $ 73.8 $ (325.5 ) $ 266.2 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17.2 $ 0.9 $ — $ 144.4 $ 162.5 Other Temporary Investments Restricted Cash (a) 233.8 9.1 — 36.8 279.7 Fixed Income Securities – Mutual Funds 80.5 — — — 80.5 Equity Securities – Mutual Funds (b) 25.4 — — — 25.4 Total Other Temporary Investments 339.7 9.1 — 36.8 385.6 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37.7 528.4 190.3 (303.7 ) 452.7 Cash Flow Hedges: Commodity Hedges (c) — 31.9 — (15.1 ) 16.8 Fair Value Hedges — 0.6 — 2.0 2.6 Total Risk Management Assets 37.7 560.9 190.3 (316.8 ) 472.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,526.4 $ 1,524.2 $ 190.3 $ (125.0 ) $ 3,115.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65.3 $ 431.9 $ 36.7 $ (335.5 ) $ 198.4 Cash Flow Hedges: Commodity Hedges (c) — 26.6 2.8 (15.1 ) 14.3 Interest Rate/Foreign Currency Hedges — 1.0 — — 1.0 Fair Value Hedges — 6.8 — 2.0 8.8 Total Risk Management Liabilities $ 65.3 $ 466.3 $ 39.5 $ (348.6 ) $ 222.5
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 14.8 $ — $ — $ 0.1 $ 14.9 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) 0.2 13.9 12.2 (10.6 ) 15.7 Total Assets $ 15.0 $ 13.9 $ 12.2 $ (10.5 ) $ 30.6 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 17.8 $ 0.5 $ (13.6 ) $ 4.9 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.6 $ — $ — $ — $ 15.6 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) 0.2 20.2 17.7 (9.4 ) 28.7 Total Assets $ 15.8 $ 20.2 $ 17.7 $ (9.4 ) $ 44.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 20.4 $ 1.9 $ (9.4 ) $ 13.1 (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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
Nuclear Trust Fund Investments	December 31, 2015 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 168.3 $ — $ — $ 20.0 $ — $ — Fixed Income Securities: United States Government 731.1 35.9 (2.6 ) 697.0 44.6 (5.0 ) Corporate Debt 57.9 3.2 (1.1 ) 47.8 4.5 (1.0 ) State and Local Government 22.2 1.1 (0.3 ) 208.5 1.2 (0.3 ) Subtotal Fixed Income Securities 811.2 40.2 (4.0 ) 953.3 50.3 (6.3 ) Equity Securities – Domestic 1,126.9 571.6 (79.3 ) 1,122.4 598.8 (79.2 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106.4 $ 611.8 $ (83.3 ) $ 2,095.7 $ 649.1 $ (85.5 )
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2015 2014 2013 (in millions) Proceeds from Investment Sales $ 2,218.4 $ 1,031.8 $ 858.4 Purchases of Investments 2,272.0 1,086.4 910.0 Gross Realized Gains on Investment Sales 69.1 32.3 18.3 Gross Realized Losses on Investment Sales 53.0 15.4 8.1
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 167.2 1 year – 5 years 361.0 5 years – 10 years 129.4 After 10 years 153.6 Total $ 811.2
Fair Value, Assets and Liabilities Measured on Recurring Basis	I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 15.9 $ 16.0 $ (6.4 ) $ 25.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.4 — — 10.6 20.0 Fixed Income Securities: United States Government — 697.0 — — 697.0 Corporate Debt — 47.8 — — 47.8 State and Local Government — 208.5 — — 208.5 Subtotal Fixed Income Securities — 953.3 — — 953.3 Equity Securities – Domestic (b) 1,122.4 — — — 1,122.4 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131.8 953.3 — 10.6 2,095.7 Total Assets $ 1,131.9 $ 969.2 $ 16.0 $ 4.2 $ 2,121.3 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.2 $ 11.4 $ 1.3 $ (6.3 ) $ 6.6 (a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.7 $ 27.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 16.0 3.2 19.2 Total Assets $ — $ — $ 16.0 $ 30.9 $ 46.9 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.8 $ 0.1 $ 2.7 $ 3.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 0.4 $ — $ — $ 28.3 $ 28.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 52.3 — 52.3 Total Assets $ 0.4 $ — $ 52.3 $ 28.3 $ 81.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 1.1 $ 3.9 $ (0.1 ) $ 4.9
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.7 $ (0.1 ) $ 0.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.5 $ 0.1 $ (0.4 ) $ 0.2 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.6 $ 0.7 $ (0.4 ) $ 0.9
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2015 2014 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,572.7 $ 21,201.3 $ 18,512.4 (a) $ 20,960.5 (b) APCo 3,930.7 4,416.7 3,958.7 4,711.2 I&M 2,000.0 2,193.6 2,019.6 2,255.1 OPCo 2,157.7 2,472.7 2,286.8 2,709.5 PSO 1,286.1 1,402.9 1,036.7 1,216.2 SWEPCo 2,273.5 2,417.2 2,132.4 2,402.6 (a) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 3.6 $ — $ — $ 1.6 $ 5.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.9 (0.1 ) 0.8 Total Assets $ 3.6 $ — $ 0.9 $ 1.5 $ 6.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 5.5 $ 0.1 $ (0.4 ) $ 5.2 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.7 $ — $ — $ 1.7 $ 14.4 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 0.4 (0.4 ) — Total Assets $ 12.7 $ — $ 0.4 $ 1.3 $ 14.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.7 $ 0.9 $ (0.5 ) $ 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 investment in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. 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, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Purchases, Issuances and Settlements (d) (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (e) (f) 28.7 — — — — — Transfers out of Level 3 (f) (g) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Purchases, Issuances and Settlements (d) (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (e) (f) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (f) (g) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2012 $ 85.4 $ 11.0 $ 7.5 $ 15.4 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (9.2 ) (3.6 ) (2.4 ) (5.0 ) — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 37.5 — — 0.3 — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.5 ) — — — — — Purchases, Issuances and Settlements (d) (15.8 ) 0.5 0.4 0.8 — — Transfers into Level 3 (e) (f) 19.0 1.3 0.9 1.9 — — Transfers out of Level 3 (f) (g) (3.6 ) (0.9 ) (0.6 ) (1.3 ) — — Transfer of OPCo Generation to Parent — — — (12.1 ) — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 7.1 2.3 1.4 2.9 — — Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — (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 the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2015 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 212.3 $ 70.3 Discounted Cash Flow Forward Market Price (a) $ 9.69 $ 165.36 $ 36.35 Counterparty Credit Risk (b) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) (6.99 ) 10.34 1.10 Total $ 220.7 $ 73.8 Significant Unobservable Inputs December 31, 2014 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157.3 $ 37.0 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33.0 2.5 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190.3 $ 39.5 Significant Unobservable Inputs December 31, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 7.9 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 4.3 0.3 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 12.2 $ 0.5 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 5.8 $ 1.8 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11.9 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17.7 $ 1.9 Significant Unobservable Inputs December 31, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.0 $ 0.2 Discounted Cash Flow Forward Market Price $ 12.61 $ 47.24 $ 32.38 FTRs 0.3 1.8 Discounted Cash Flow Forward Market Price (6.96 ) 8.43 1.34 Total $ 6.3 $ 2.0 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input(a) Low High Average (in millions) Energy Contracts $ 6.4 $ 1.2 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9.6 0.1 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16.0 $ 1.3 Significant Unobservable Inputs December 31, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 16.0 $ 0.1 Discounted Cash Flow Forward Market Price $ 41.61 $ 165.36 $ 86.84 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 45.1 $ 3.9 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7.2 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52.3 $ 3.9 Significant Unobservable Inputs December 31, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.7 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.9 $ 0.1 Discounted Cash Flow Forward Market Price $ (6.96 ) $ 8.43 $ 1.34 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.4 $ 0.9 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Details of Income Taxes as Reported	AEP Years Ended December 31, 2015 2014 2013 (in millions) Federal: Current $ 107.3 $ 22.8 $ (53.4 ) Deferred 774.8 800.1 678.6 Total Federal 882.1 822.9 625.2 State and Local: Current 14.5 22.8 28.7 Deferred 23.0 56.9 23.8 Total State and Local 37.5 79.7 52.5 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	AEP Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 2,052.3 $ 1,638.0 $ 1,484.2 Discontinued Operations (Net of Income Tax of $6.2, $39 and $5.9 in 2015, 2014 and 2013, Respectively) (283.7 ) (47.5 ) (10.3 ) Income Tax Expense Before Discontinued Operations 919.6 902.6 677.7 Pretax Income $ 2,688.2 $ 2,493.1 $ 2,151.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 940.9 $ 872.6 $ 753.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 53.6 54.0 46.6 Investment Tax Credits, Net (11.6 ) (12.8 ) (14.0 ) State and Local Income Taxes, Net 24.4 54.3 29.1 Removal Costs (28.8 ) (23.9 ) (20.9 ) AFUDC (51.6 ) (41.8 ) (30.5 ) Valuation Allowance 17.2 (2.5 ) 5.1 U.K. Windfall Tax — — (79.5 ) Other (24.5 ) 2.7 (11.3 ) Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 $ 677.7 Effective Income Tax Rate 34.2 % 36.2 % 31.5 %
Reconciliation of Significant Temporary Differences	AEP December 31, 2015 2014 (in millions) Deferred Tax Assets $ 2,503.9 $ 2,650.7 Deferred Tax Liabilities (14,237.1 ) (13,503.1 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 ) Property Related Temporary Differences $ (8,533.3 ) $ (7,883.4 ) Amounts Due from Customers for Future Federal Income Taxes (263.5 ) (255.2 ) Deferred State Income Taxes (872.0 ) (796.9 ) Securitized Assets (633.2 ) (753.2 ) Regulatory Assets (873.6 ) (694.1 ) Deferred Income Taxes on Other Comprehensive Loss 72.2 59.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Net Operating Loss Carryforward 39.6 46.4 Tax Credit Carryforward 85.0 144.3 Valuation Allowance (130.0 ) (55.6 ) All Other, Net (9.8 ) (53.4 ) Net Deferred Tax Liabilities $ (11,733.2 ) $ (10,852.4 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4
Appalachian Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4
Indiana Michigan Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4
Ohio Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4
Public Service Co Of Oklahoma [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4
Southwestern Electric Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2013 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 58.4 $ (49.1 ) $ 92.6 $ 7.7 $ (10.9 ) Deferred 75.7 129.1 134.5 53.8 81.9 Deferred Investment Tax Credits (1.2 ) (4.9 ) (1.4 ) 4.4 (1.5 ) Income Tax Expense $ 132.9 $ 75.1 $ 225.7 $ 65.9 $ 69.5
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 340.6 $ 215.4 $ 193.2 Income Tax Expense 194.3 154.9 132.9 Pretax Income $ 534.9 $ 370.3 $ 326.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 187.2 $ 129.6 $ 114.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.8 23.5 20.3 Investment Tax Credits, Net (0.3 ) (0.6 ) (1.2 ) State and Local Income Taxes, Net 7.2 6.5 2.7 Removal Costs (9.9 ) (6.8 ) (6.5 ) AFUDC (7.0 ) (3.8 ) (1.4 ) Valuation Allowance 1.7 (2.5 ) 5.1 Other (4.4 ) 9.0 (0.2 ) Income Tax Expense $ 194.3 $ 154.9 $ 132.9 Effective Income Tax Rate 36.3 % 41.8 % 40.8 % I&M Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 204.8 $ 155.6 $ 177.5 Income Tax Expense 96.1 79.6 75.1 Pretax Income $ 300.9 $ 235.2 $ 252.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 105.3 $ 82.3 $ 88.4 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 9.5 12.9 10.1 Investment Tax Credits, Net (3.3 ) (4.9 ) (4.9 ) State and Local Income Taxes, Net 5.8 7.7 (0.9 ) Removal Costs (12.6 ) (11.3 ) (9.4 ) AFUDC (6.2 ) (10.0 ) (10.6 ) Other (2.4 ) 2.9 2.4 Income Tax Expense $ 96.1 $ 79.6 $ 75.1 Effective Income Tax Rate 31.9 % 33.8 % 29.7 % OPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 232.7 $ 216.4 $ 410.0 Income Tax Expense 126.5 132.2 225.7 Pretax Income $ 359.2 $ 348.6 $ 635.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 125.7 $ 122.0 $ 222.5 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 8.2 6.7 6.8 Investment Tax Credits, Net (0.1 ) (0.2 ) (1.4 ) State and Local Income Taxes, Net 0.7 8.8 3.3 Other (8.0 ) (5.1 ) (5.5 ) Income Tax Expense $ 126.5 $ 132.2 $ 225.7 Effective Income Tax Rate 35.2 % 37.9 % 35.5 % PSO Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 92.5 $ 86.9 $ 97.8 Income Tax Expense 51.3 50.6 65.9 Pretax Income $ 143.8 $ 137.5 $ 163.7 Income Taxes on Pretax Income at Statutory Rate (35%) $ 50.3 $ 48.1 $ 57.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.5 0.2 0.2 Investment Tax Credits, Net (1.8 ) (0.8 ) (0.8 ) State and Local Income Taxes, Net 5.1 4.8 5.4 AFUDC (3.1 ) (1.1 ) (1.5 ) Tax Adjustments (0.3 ) (1.2 ) 5.3 Other 0.6 0.6 — Income Tax Expense $ 51.3 $ 50.6 $ 65.9 Effective Income Tax Rate 35.7 % 36.8 % 40.3 % SWEPCo Years Ended December 31, 2015 2014 2013 (in millions) Net Income $ 196.0 $ 144.6 $ 153.8 Income Tax Expense 84.8 66.4 69.5 Pretax Income $ 280.8 $ 211.0 $ 223.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 98.3 $ 73.8 $ 78.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.1 2.9 3.1 Depletion (5.5 ) (4.1 ) (3.5 ) Investment Tax Credits, Net (1.4 ) (1.4 ) (1.5 ) State and Local Income Taxes, Net 4.8 3.1 (1.4 ) AFUDC (9.2 ) (4.2 ) (2.4 ) Other (5.3 ) (3.7 ) (2.9 ) Income Tax Expense $ 84.8 $ 66.4 $ 69.5 Effective Income Tax Rate 30.2 % 31.5 % 31.1 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 412.9 $ 446.4 Deferred Tax Liabilities (2,939.9 ) (2,711.2 ) Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) Property Related Temporary Differences $ (1,866.0 ) $ (1,801.9 ) Amounts Due from Customers for Future Federal Income Taxes (68.2 ) (70.4 ) Deferred State Income Taxes (308.7 ) (239.7 ) Regulatory Assets (169.1 ) (113.7 ) Securitized Assets (114.8 ) (122.6 ) Deferred Income Taxes on Other Comprehensive Loss 1.5 (2.7 ) Net Operating Loss Carryforward 1.0 9.8 Tax Credit Carryforward 19.2 46.2 All Other, Net (21.9 ) 30.2 Net Deferred Tax Liabilities $ (2,527.0 ) $ (2,264.8 ) I&M December 31, 2015 2014 (in millions) Deferred Tax Assets $ 837.4 $ 911.8 Deferred Tax Liabilities (2,198.9 ) (2,190.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) Property Related Temporary Differences $ (521.6 ) $ (418.7 ) Amounts Due from Customers for Future Federal Income Taxes (42.7 ) (40.6 ) Deferred State Income Taxes (124.8 ) (138.9 ) Deferred Income Taxes on Other Comprehensive Loss 9.0 7.7 Accrued Nuclear Decommissioning (614.6 ) (611.0 ) Regulatory Assets (70.2 ) (74.7 ) All Other, Net 3.4 (2.0 ) Net Deferred Tax Liabilities $ (1,361.5 ) $ (1,278.2 ) OPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 162.4 $ 171.8 Deferred Tax Liabilities (1,545.6 ) (1,528.1 ) Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) Property Related Temporary Differences $ (1,022.8 ) $ (926.5 ) Amounts Due from Customers for Future Federal Income Taxes (44.6 ) (47.6 ) Deferred State Income Taxes (34.4 ) (34.2 ) Regulatory Assets (220.0 ) (242.4 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (3.0 ) Deferred Fuel and Purchased Power (117.4 ) (145.5 ) All Other, Net 58.3 42.9 Net Deferred Tax Liabilities $ (1,383.2 ) $ (1,356.3 ) PSO December 31, 2015 2014 (in millions) Deferred Tax Assets $ 141.2 $ 110.7 Deferred Tax Liabilities (1,113.0 ) (1,016.7 ) Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) Property Related Temporary Differences $ (861.9 ) $ (805.2 ) Amounts Due from Customers for Future Federal Income Taxes (2.2 ) (0.7 ) Deferred State Income Taxes (117.0 ) (109.3 ) Regulatory Assets (54.3 ) (39.6 ) Deferred Income Taxes on Other Comprehensive Loss (2.3 ) (2.7 ) Deferred Federal Income Taxes on Deferred State Income Taxes 46.6 43.9 Net Operating Loss Carryforward 7.1 6.4 Tax Credit Carryforward 0.6 0.7 All Other, Net 11.6 0.5 Net Deferred Tax Liabilities $ (971.8 ) $ (906.0 ) SWEPCo December 31, 2015 2014 (in millions) Deferred Tax Assets $ 194.7 $ 186.1 Deferred Tax Liabilities (1,594.5 ) (1,528.2 ) Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 ) Property Related Temporary Differences $ (1,275.1 ) $ (1,235.1 ) Amounts Due from Customers for Future Federal Income Taxes (47.8 ) (44.1 ) Deferred State Income Taxes (132.3 ) (124.1 ) Regulatory Assets (26.1 ) (19.4 ) Deferred Income Taxes on Other Comprehensive Loss 5.0 4.0 Impairment Loss - Turk Plant 20.7 21.1 Net Operating Loss Carryforward 19.7 21.9 All Other, Net 36.1 33.6 Net Deferred Tax Liabilities $ (1,399.8 ) $ (1,342.1 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Kentucky $ 80.7 2035 AEP Louisiana 376.3 2030 AEP Oklahoma 378.1 2035 AEP West Virginia 49.9 2033 APCo West Virginia 24.8 2033 OPCo West Virginia 25.2 2033 PSO Oklahoma 181.8 2035 SWEPCo Louisiana 375.7 2030 SWEPCo Oklahoma 3.2 2035
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 85.0 $ 47.8 $ 23.4 $ 23.4 APCo 19.1 5.8 — — I&M 3.7 3.2 — — OPCo 19.3 1.0 — — PSO 0.6 0.6 23.4 23.4 SWEPCo 0.7 0.6 — —
Summary of Interest Income, Expense And Reversal	Years Ended December 31, 2015 2014 Company Interest Expense Interest Income Reversal of Prior Period Interest Expense Interest Expense Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 2.7 $ 0.8 $ — $ 2.9 $ 1.2 $ 2.0 APCo 0.4 — — — — 0.2 I&M 0.2 — — — — 0.3 OPCo 1.0 — — 0.1 — 0.2 PSO 0.1 — — 0.1 — 0.1 SWEPCo 0.4 — — 0.2 — 0.2 Year Ended December 31, 2013 Company Interest Interest Income Reversal of Prior Period Interest Expense (in millions) AEP $ 1.5 $ 51.8 $ — APCo — 1.1 — I&M — 0.6 — OPCo — 1.9 — PSO — 0.1 — SWEPCo 0.2 — —
Amounts Accrued for Receipt of Interest	December 31, Company 2015 2014 (in millions) AEP $ 44.7 $ 44.0 APCo — — I&M — — OPCo — — PSO — — SWEPCo — —
Amounts Accrued for Payment of Interest and Penalties	December 31, Company 2015 2014 (in millions) AEP $ 7.2 $ 5.9 APCo — — I&M 0.6 0.5 OPCo 0.6 0.4 PSO 0.4 0.3 SWEPCo 1.4 1.0
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Increase – Settlements with Taxing Authorities — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2013 $ 267.2 $ 5.3 $ 15.1 $ 11.1 $ 2.3 $ 9.5 Increase – Tax Positions Taken During a Prior Period — — — — — — Decrease – Tax Positions Taken During a Prior Period (93.6 ) (4.1 ) (11.9 ) (9.0 ) (0.1 ) (3.2 ) Increase – Tax Positions Taken During the Current Year 1.8 — — — — 1.3 Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations (0.2 ) — — — — — Balance as of December 31, 2013 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2015 2014 2013 (in millions) AEP $ 100.2 $ 97.2 $ 86.9 APCo 0.2 — — I&M 1.6 1.6 1.2 OPCo 4.5 4.5 0.7 PSO 0.9 0.9 0.8 SWEPCo 6.0 4.9 4.4

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4
Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0
Nuclear Fuel Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Appalachian Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4
Indiana Michigan Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2016 $ 147.8 $ 73.9 2017 147.8 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 Later Years 295.0 147.5 Total Future Minimum Lease Payments $ 1,034.0 $ 517.0
Indiana Michigan Power Co [Member] | Nuclear Fuel Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments I&M (in millions) 2016 $ 26.9 2017 5.8 2018 2.4 Total Future Minimum Lease Payments $ 35.1
Ohio Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4
Public Service Co Of Oklahoma [Member]
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4
Southwestern Electric Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 Year Ended December 31, 2013 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 326.6 $ 17.5 $ 95.6 $ 57.8 $ 4.1 $ 6.3 Amortization of Capital Leases 73.9 6.3 11.3 7.8 4.1 15.5 Interest on Capital Leases 28.3 1.4 1.9 4.1 0.8 8.1 Total Lease Rental Costs $ 428.8 (a) $ 25.2 $ 108.8 $ 69.7 $ 9.0 $ 29.9 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million , $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 104.4 $ 14.1 $ 18.7 $ — $ 9.6 $ 35.4 Other Property, Plant and Equipment 683.0 19.4 100.4 22.6 16.5 159.5 Total Property, Plant and Equipment 787.4 33.5 119.1 22.6 26.1 194.9 Accumulated Amortization 240.0 14.0 15.9 8.0 11.8 80.1 Net Property, Plant and Equipment Under Capital Leases $ 547.4 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 114.8 Obligations Under Capital Leases: Noncurrent Liability $ 440.4 $ 14.4 $ 61.1 $ 11.0 $ 10.9 $ 91.0 Liability Due Within One Year 111.4 5.1 42.1 3.6 3.4 17.6 Total Obligations Under Capital Leases $ 551.8 (a) $ 19.5 $ 103.2 $ 14.6 $ 14.3 $ 108.6 (a) Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 112.9 $ 9.8 $ 36.6 $ 4.4 $ 4.3 $ 26.1 2017 76.2 9.4 12.1 4.0 4.1 18.2 2018 54.9 8.4 6.5 3.1 2.9 12.7 2019 38.7 6.4 3.0 1.0 1.6 11.4 2020 27.7 5.7 2.7 0.6 1.0 9.7 Later Years 110.7 26.5 20.3 1.4 2.6 40.3 Total Future Minimum Lease Payments 421.1 66.2 81.2 14.5 16.5 118.4 Less Estimated Interest Element 77.6 20.8 18.2 1.3 1.9 20.9 Estimated Present Value of Future Minimum Lease Payments $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 239.1 $ 15.6 $ 92.7 $ 8.8 $ 4.8 $ 6.3 2017 228.7 15.2 90.9 8.3 3.9 5.3 2018 219.9 13.8 89.7 6.9 3.5 4.8 2019 211.2 12.4 88.5 5.4 2.9 4.5 2020 202.8 11.8 85.1 4.5 2.4 4.2 Later Years 452.3 36.0 173.8 20.2 4.7 16.5 Total Future Minimum Lease Payments $ 1,554.0 $ 104.8 $ 620.7 $ 54.1 $ 22.2 $ 41.6
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 33.4 APCo 4.8 I&M 3.2 OPCo 5.3 PSO 2.8 SWEPCo 3.4

Financing Activities (Tables)

Financing Activities (Tables)	12 Months Ended
	Dec. 31, 2015
AEP Common Stock	Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2012 506,004,962 20,336,592 Issued 2,109,002 — Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Lines of Credit and Short-term Debt	December 31, 2015 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 675.0 0.30 % $ 744.0 0.22 % Commercial Paper 125.0 0.81 % 602.0 0.59 % Total Short-term Debt $ 800.0 $ 1,346.0 (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	Years Ended December 31, 2015 2014 2013 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.22 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 34.1 $ 40.1 $ 34.9
Customer Accounts Receivable Managed Portfolio	December 31, 2015 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 924.8 $ 974.5 Total Principal Outstanding 675.0 744.0 Delinquent Securitized Accounts Receivable 48.3 43.9 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 17.5 12.9 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 357.8 335.4
Appalachian Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 —
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Indiana Michigan Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 —
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Ohio Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 —
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Public Service Co Of Oklahoma [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 —
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8
Southwestern Electric Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2015 2015 2014 2015 2014 AEP (in millions) Senior Unsecured Notes 2015-2045 5.09% 1.65%-8.13% 1.65%-8.13% $ 13,629.1 $ 12,562.1 Pollution Control Bonds (a) 2015-2038 (b) 2.71% 0.01%-6.30% 0.04%-6.30% 1,784.8 1,951.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.47% 0.925%-6.60% 0.983%-8.03% 264.7 274.1 (d) Securitization Bonds 2015-2031 3.66% 0.88%-6.25% 0.88%-6.25% 2,024.0 2,360.9 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2059 1.62% 1.15%-13.718% 1.15%-13.718% 1,604.5 1,098.0 Total Long-term Debt Outstanding $ 19,572.7 $ 18,512.4 (d) APCo Senior Unsecured Notes 2015-2045 5.39% 3.40%-7.00% 3.40%-7.95% $ 2,970.4 $ 2,976.1 Pollution Control Bonds (a) 2015-2038 (b) 1.70% 0.01%-5.375% 0.04%-5.375% 616.5 530.6 Notes Payable – Affiliated 2015 3.125% — 86.0 Securitization Bonds 2024-2031 2.85% 2.008%-3.772% 2.008%-3.772% 341.5 363.7 Other Long-term Debt 2026 13.718% 13.718% 13.718% 2.3 2.3 Total Long-term Debt Outstanding $ 3,930.7 $ 3,958.7 I&M Senior Unsecured Notes 2015-2037 5.82% 3.20%-7.00% 3.20%-7.00% $ 1,117.0 $ 1,240.8 Pollution Control Bonds (a) 2015-2025 (b) 1.79% 0.01%-4.625% 0.04%-4.625% 225.1 224.8 Notes Payable – Nonaffiliated (c) 2016-2019 1.02% 0.925%-2.12% 0.983%-2.12% 175.5 176.7 Spent Nuclear Fuel Obligation (e) 265.6 265.5 Other Long-term Debt 2015-2025 2.14% 1.81%-6.00% 1.55%-6.00% 216.8 111.8 Total Long-term Debt Outstanding $ 2,000.0 $ 2,019.6 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,938.9 $ 1,937.3 Pollution Control Bonds (a) 2015-2038 (b) 5.80% 5.80% 3.125%-5.80% 32.2 118.2 Securitization Bonds 2018-2020 1.56% 0.958%-2.049% 0.958%-2.049% 185.3 229.9 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.3 1.4 Total Long-term Debt Outstanding $ 2,157.7 $ 2,286.8 PSO Senior Unsecured Notes 2016-2045 5.11% 3.17%-6.625% 4.40%-6.625% $ 1,142.7 $ 893.0 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.80% 1.587%-3.00% 1.482%-3.00% 130.8 131.1 Total Long-term Debt Outstanding $ 1,286.1 $ 1,036.7 SWEPCo Senior Unsecured Notes 2015-2045 5.28% 3.55%-6.45% 3.55%-6.45% $ 1,961.0 $ 1,816.9 Pollution Control Bonds (a) 2015-2019 (b) 3.62% 1.60%-4.95% 3.25%-4.95% 134.5 134.4 Notes Payable – Nonaffiliated (c) 2024-2032 5.15% 4.58%-6.37% 4.58%-6.37% 78.6 81.9 Other Long-term Debt 2017 1.82% 1.82% 1.73% 99.4 99.2 Total Long-term Debt Outstanding $ 2,273.5 $ 2,132.4 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. (e) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ).
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2016 $ 1,831.8 $ 318.0 $ 162.9 $ 395.9 $ 275.4 $ 3.3 2017 2,689.6 273.5 68.5 46.4 0.5 353.3 2018 1,726.9 124.0 318.0 397.0 0.5 384.9 2019 1,813.2 180.4 484.1 48.0 250.5 456.7 2020 368.2 24.9 1.8 0.1 13.1 3.3 After 2020 11,262.4 3,045.0 975.1 1,283.1 753.5 1,087.4 Principal Amount 19,692.1 3,965.8 2,010.4 2,170.5 1,293.5 2,288.9 Unamortized Discount, Net and Debt Issuance Costs (119.4 ) (35.1 ) (10.4 ) (12.8 ) (7.4 ) (15.4 ) Total Long-term Debt Outstanding $ 19,572.7 $ 3,930.7 $ 2,000.0 $ 2,157.7 $ 1,286.1 $ 2,273.5
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 Year Ended December 31, 2014 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2014 Limit (in millions) APCo $ 44.2 $ 542.2 $ 12.6 $ 104.5 $ 48.5 $ 600.0 I&M 150.7 158.9 73.2 39.1 (129.0 ) 500.0 OPCo 120.3 405.4 34.8 107.3 312.5 400.0 PSO 177.0 — 93.7 — (154.2 ) 300.0 SWEPCo 153.5 51.3 71.0 24.4 41.0 350.0
Nonutility Money Pool Activity	Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 2015 (in millions) $ 2.0 $ 2.0 $ 2.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2015 2014 2013 Maximum Interest Rate 0.87 % 0.59 % 0.43 % Minimum Interest Rate 0.37 % 0.24 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2015 2014 2013 2015 2014 2013 APCo 0.53 % 0.29 % 0.33 % 0.47 % 0.29 % 0.33 % I&M 0.49 % 0.31 % 0.36 % 0.48 % 0.30 % 0.32 % OPCo — % 0.27 % 0.33 % 0.48 % 0.34 % 0.32 % PSO 0.49 % 0.29 % 0.34 % 0.48 % — % 0.33 % SWEPCo 0.53 % 0.29 % 0.34 % 0.48 % 0.32 % 0.36 %
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool	Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2015 0.87 % 0.37 % 0.48 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.2 $ — $ 0.4 I&M 0.8 0.1 0.1 OPCo — — 0.5 PSO 0.1 0.3 — SWEPCo 0.1 0.2 —
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 0.4 $ 0.3 $ 0.1 I&M 0.1 0.1 0.9 OPCo 1.3 0.2 0.2 PSO 0.4 — 0.1 SWEPCo 0.4 — 0.1
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2015 2014 (in millions) APCo $ 135.4 $ 159.8 I&M 134.8 137.5 OPCo 351.4 365.8 PSO 116.1 112.9 SWEPCo 151.8 148.7
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 7.6 $ 8.9 $ 6.5 I&M 8.4 7.9 6.5 OPCo 30.7 28.8 21.6 PSO 5.8 5.9 5.6 SWEPCo 7.0 6.8 5.9
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 1,453.8 $ 1,519.3 $ 1,443.0 I&M 1,553.0 1,488.6 1,458.8 OPCo 2,569.4 2,647.6 2,620.5 PSO 1,326.1 1,321.1 1,232.4 SWEPCo 1,597.8 1,655.8 1,533.8

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Total Fair Value of Stock Options Vested and Total Intrinsic Value of Options Exercised [Table Text Block]	Years Ended December 31, Stock Options 2015 2014 2013 (in millions) Intrinsic Value of Options Exercised (a) $ — $ — $ 3.1 (a) Intrinsic value is calculated as market price at exercise dates less the option exercise price.
Summary of Stock Option Transactions [Table Text Block]	2015 2014 2013 Options Weighted Average Exercise Price Options Weighted Average Exercise Price Options Weighted Average Exercise Price (in thousands) (in thousands) (in thousands) Outstanding as of January 1, — NA — NA 188.5 $ 30.17 Granted — NA — NA — NA Exercised/Converted — NA — NA (187.5 ) 30.18 Forfeited/Expired — NA — NA (1.0 ) 27.95 Outstanding as of December 31, — NA — NA — NA Options Exercisable as of December 31, — NA — NA — NA NA Not applicable.
Performance Units and Reinvested Dividends on Outstanding Performance Units [Table Text Block]	Years Ended December 31, Performance Units 2015 2014 2013 Awarded Units (in thousands) 575.0 16.9 1,284.2 Weighted Average Unit Fair Value at Grant Date $ 59.19 $ 49.73 $ 46.23 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2015 2014 2013 Awarded Units (in thousands) 103.6 98.9 100.9 Weighted Average Fair Value at Grant Date $ 54.35 $ 53.35 $ 45.42 Vesting Period (in years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s employment ends.
Summary of Performance Scores and Performance Units Earned [Table Text Block]	Years Ended December 31, Performance Units 2015 2014 2013 Certified Performance Score 176.3 % 147.8 % 118.8 % Performance Units Earned 1,202,107 889,697 749,219 Performance Units Mandatorily Deferred as AEP Career Shares 41,707 40,831 72,883 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 54,074 39,526 39,691 Performance Units to be Paid in Cash 1,106,326 809,340 636,645
Summary of Cash Payouts for Performance Units and Career Shares [Table Text Block]	The cash payouts for the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, Performance Units and AEP Career Shares 2015 2014 2013 (in millions) Cash Payouts for Performance Units $ 48.1 $ 29.3 $ 43.9 Cash Payouts for AEP Career Share Distributions 3.0 4.3 3.7
Summary of Units Awarded and Fair Value of Restricted Stock Units [Table Text Block]	Years Ended December 31, Restricted Stock Units 2015 2014 2013 Awarded Units (in thousands) 397.5 64.1 644.4 Weighted Average Grant Date Fair Value $ 58.56 $ 50.36 $ 46.24
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested [Table Text Block]	Years Ended December 31, Restricted Stock Units 2015 2014 2013 (in millions) Fair Value of Restricted Stock Units Vested $ 18.3 $ 18.7 $ 15.3 Intrinsic Value of Restricted Stock Units Vested (a) 24.2 24.9 20.4 (a) Intrinsic value is calculated as market price at exercise date.
Status of Nonvested Restricted Shares and Restricted Stock Units [Table Text Block]	Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2015 783.0 $ 44.59 Granted 397.5 58.56 Vested (425.4 ) 42.94 Forfeited (33.8 ) 51.07 Nonvested as of December 31, 2015 721.3 52.48
Stock Unit Accumulation Plan for Non-employee Directors [Table Text Block]	Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2015 2014 2013 Awarded Units (in thousands) 24.9 25.4 32.7 Weighted Average Grant Date Fair Value $ 55.46 $ 54.08 $ 45.81
Compensation Cost and Actual Tax Benefit Realized for Tax Deductions from Compensation Cost for Share-based Payment Arrangements [Table Text Block]	Years Ended December 31, Share-based Compensation Plans 2015 2014 2013 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 63.8 $ 85.4 $ 56.4 Actual Tax Benefit Realized 22.3 29.9 19.7 Total Compensation Cost Capitalized 20.3 23.1 13.2 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.
Cash Received from Stock Options Exercised and Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised [Table Text Block]	Years Ended December 31, Share-based Compensation Plans 2015 2014 2013 (in millions) Cash Received from Stock Options Exercised $ — $ — $ 5.7 Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised — — 1.0

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Appalachian Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6
Central Machine Shop	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2
Affiliate Railcar Agreement	December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 —
Ownership and Investment in OVEC	December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6
Related Party Sales of Property	Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4
Indiana Michigan Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9
Coal Transloading	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Railcar Maintenance	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6
Central Machine Shop	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2
Affiliate Railcar Agreement	December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 —
Ownership and Investment in OVEC	December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6
Related Party Sales of Property	Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4
Ohio Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 92.7 $ 84.7 $ 40.6 I&M 38.0 39.7 19.9 OPCo 81.0 17.0 8.9
Coal Transloading	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 15.8 $ 16.2 $ 6.8 OPCo — — 0.3 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 15.6 (a) (a) Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Railcar Maintenance	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 16.1 $ 22.7 $ 19.7 AGR 4.9 5.2 — APCo 37.7 36.1 30.9 KPCo 4.6 5.0 0.1 OPCo — — 40.6 AEP River Operations LLC – (Nonutility Subsidiary of AEP) 15.5 25.3 22.6
Central Machine Shop	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2
Ownership and Investment in OVEC	December 31, 2015 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 87.2 $ 96.9 $ 104.4 I&M 43.7 48.5 52.2 OPCo 110.8 123.1 132.6
Related Party Sales of Property	Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4
Public Service Co Of Oklahoma [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Coordination Agreement	Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 )
Railcar Maintenance	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Central Machine Shop	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2
Affiliate Railcar Agreement	December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 —
Related Party Sales of Property	Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4
Southwestern Electric Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Sales under Interconnection Agreement $ 193.7 $ 218.2 $ 924.3 $ — $ — Direct Sales to East Affiliates 129.0 — 152.7 — — Direct Sales to West Affiliates 0.6 0.4 0.8 10.8 35.4 Direct Sales to AEPEP — — — — (0.1 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.4 (0.7 ) 53.4 — 14.7 Other Revenues 23.8 1.5 35.7 3.4 1.8 Total Affiliated Revenues $ 347.5 $ 219.4 $ 1,166.9 $ 14.2 $ 51.8 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR $ — $ — $ 238.5 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 496.4 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR — — 1,148.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,192.7 $ 11.0 $ 3.8 Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2013 Purchases under Interconnection Agreement $ 830.9 $ 181.7 $ 199.3 $ — $ — Direct Purchases from East Affiliates — — — 1.5 0.4 Direct Purchases from West Affiliates — — — 35.4 10.8 Direct Purchases from AEGCo — 251.5 148.4 — — Natural Gas Purchases from AEPES — — 2.0 — — Total Affiliated Purchases $ 830.9 $ 433.2 $ 349.7 $ 36.9 $ 11.2 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Coordination Agreement	Years Ended December 31, Company 2015 2014 2013 (in millions) PSO $ 15.0 $ 14.1 $ 14.7 SWEPCo (15.0 ) (14.1 ) (14.7 )
Railcar Maintenance	AEGCo Years Ended December 31, Company 2015 2014 2013 (in millions) I&M $ 2.0 $ 2.5 $ 1.1 PSO 0.2 0.3 0.1 SWEPCo 2.8 3.3 1.2 OPCo Years Ended December 31, Company 2013 (in millions) I&M $ 1.3 (a) PSO 0.1 SWEPCo 1.2 (a) Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
Central Machine Shop	Years Ended December 31, Company 2015 2014 2013 (in millions) AEGCo $ 0.1 $ 0.1 $ — AGR 2.7 2.8 — I&M 2.5 1.7 2.5 KPCo 1.3 1.2 0.7 OPCo — — 4.7 PSO 0.2 0.3 0.6 SWEPCo 0.8 0.1 0.2
Affiliate Railcar Agreement	December 31, 2015 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) APCo $ — $ — $ 0.3 $ 0.3 I&M — — 0.4 1.2 PSO — 0.6 — 0.6 SWEPCo — 1.8 0.6 — December 31, 2014 Billing Company Billed Company APCo I&M PSO SWEPCo (in millions) I&M $ 0.3 $ — $ 0.1 $ 1.1 PSO 0.1 1.3 — 0.7 SWEPCo 0.1 2.2 0.2 —
Related Party Sales of Property	Sales Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 9.4 $ 3.0 $ 3.2 I&M 3.0 1.3 5.0 OPCo 2.4 0.5 59.8 PSO 7.1 0.5 5.7 SWEPCo 0.8 1.2 1.6
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 8.6 $ 0.9 $ 5.2 I&M 8.1 1.4 1.0 OPCo 2.1 1.9 5.3 PSO 0.6 2.1 1.7 SWEPCo 7.4 4.0 8.4

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2015
Consolidated Assets And Liabilities Of Variable Interest Entities [Table Text Block]	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million .
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable [Text Block]	December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Consolidated Assets And Liabilities Of Variable Interest Entities [Table Text Block]	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million .
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable [Text Block]	December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Consolidated Assets And Liabilities Of Variable Interest Entities [Table Text Block]	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million .
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable [Text Block]	December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Consolidated Assets And Liabilities Of Variable Interest Entities [Table Text Block]	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million .
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable [Text Block]	December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2015 2014 2013 (in millions) APCo $ 227.5 $ 216.5 $ 174.4 I&M 139.5 133.2 119.3 OPCo 177.8 169.0 255.5 PSO 107.3 101.4 86.0 SWEPCo 141.4 140.3 125.4
Southwestern Electric Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable [Text Block]	December 31, 2015 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 25.8 $ 25.8 $ 30.7 $ 30.7 I&M 16.6 16.6 22.5 22.5 OPCo 23.3 23.3 24.7 24.7 PSO 12.6 12.6 15.3 15.3 SWEPCo 16.4 16.4 20.8 20.8
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Consolidated Assets And Liabilities Of Variable Interest Entities [Table Text Block]	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment 147.0 159.9 — — — — — 227.2 Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) 6.4 1,365.7 (c) 1.9 5.5 Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 222.3 250.8 144.6 321.5 0.3 1,290.0 83.9 113.0 Equity 0.5 — 1.3 1.9 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) Includes an intercompany item eliminated in consolidation of $76 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $68 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 Registrant Subsidiaries Other Consolidated VIEs SWEPCo Sabine I&M DCC Fuel OPCo APCo AEP Credit TCC Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 68.0 $ 97.4 $ 32.7 $ 18.1 $ 979.9 $ 238.5 $ 149.0 $ 2.4 Net Property, Plant and Equipment 145.5 158.1 — — — — — 98.0 Other Noncurrent Assets 51.1 79.7 207.3 (a) 354.4 (b) 0.5 1,641.5 (c) 1.9 3.7 Total Assets $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 LIABILITIES AND EQUITY Current Liabilities $ 36.3 $ 86.0 $ 47.1 $ 26.8 $ 894.5 $ 321.5 $ 44.3 $ 20.8 Noncurrent Liabilities 227.9 249.2 191.6 343.8 0.3 1,540.4 61.4 54.7 Equity 0.4 — 1.3 1.9 85.6 18.1 45.2 28.6 Total Liabilities and Equity $ 264.6 $ 335.2 $ 240.0 $ 372.5 $ 980.4 $ 1,880.0 $ 150.9 $ 104.1 (a) Includes an intercompany item eliminated in consolidation of $97 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . (c) Includes an intercompany item eliminated in consolidation of $75 million .
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Companys Investment In Joint Venture	December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 7.6 $ 7.6 $ 7.6 $ 7.6 Retained Earnings 7.7 7.7 3.8 3.8 Advance Due to Parent — — 56.0 56.0 SWEPCo’s Guarantee of Debt — 82.9 — 48.3 Total Investment in DHLC $ 15.3 $ 98.2 $ 67.4 $ 115.7
PATH West Virginia Transmission Co, LLC [Member]
Companys Investment In Joint Venture	December 31, 2015 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings 2.2 2.2 2.2 2.2 Total Investment in PATH-WV $ 21.0 $ 21.0 $ 21.0 $ 21.0

Property, Plant and Equipment55

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Appalachian Power Co [Member]
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization	APCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 40 - 121 3.0% 40 - 121 Transmission 1.6% 15 - 68 1.7% 15 - 87 1.6% 25 - 87 Distribution 3.6% 10 - 57 3.5% 13 - 57 3.5% 11 - 52 Other 8.3% 5 - 55 6.9% 24 - 55 7.3% 24 - 55
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization	I&M 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% 59 - 132 2.0% 59 - 132 1.9% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.5% 50 - 75 Distribution 2.8% 10 - 70 2.8% 15 - 70 2.8% 15 - 70 Other 11.8% 5 - 45 6.1% 14 - 45 4.9% 14 - 45
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Ohio Power Co [Member]
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization	OPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.7% 7 - 57 2.7% 12 - 60 Other 7.2% 5 - 50 7.0% 7 - 50 7.5% 25 - 50
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization	PSO 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 1.7% 35 - 70 1.7% 35 - 70 1.7% 35 - 70 Transmission 1.9% 40 - 75 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.5% 7 - 65 2.4% 30 - 65 2.3% 30 - 65 Other 4.6% 5 - 40 4.1% 5 - 40 4.1% 5 - 40
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (a) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (a) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (a) 475.1 519.8 171.9 315.3 744.7 (a) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 18,394.1 (a) $ 6,824.0 $ 3,741.9 $ — $ 1,264.7 $ 3,864.5 (a) Transmission 12,394.9 2,228.0 1,358.4 2,104.6 788.9 1,300.7 Distribution 17,156.6 3,258.3 1,698.4 4,087.6 2,080.2 1,894.6 Other 4,360.4 339.2 1,342.8 380.5 416.4 587.1 CWIP 3,087.8 (a) 321.5 537.2 218.7 204.8 471.7 (a) Less: Accumulated Depreciation 16,461.8 3,811.2 3,302.2 2,037.3 1,319.6 2,360.3 Total Regulated Property, Plant and Equipment - Net 38,932.0 9,159.8 5,376.5 4,754.1 3,435.4 5,758.3 Nonregulated Property, Plant and Equipment - Net 4,703.1 (b) 21.9 39.9 9.5 5.2 149.0 Total Property, Plant and Equipment - Net $ 43,635.1 (b) $ 9,181.7 $ 5,416.4 $ 4,763.6 $ 3,440.6 $ 5,907.3 (a) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. (b) Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Depreciation, Depletion and Amortization	SWEPCo 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.2% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.3% 50 - 70 2.2% 50 - 70 2.3% 50 - 70 Distribution 2.6% 25 - 65 2.7% 25 - 65 2.6% 25 - 65 Other 5.5% 5 - 51 4.8% 7 - 51 5.0% 7 - 51
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 Company ARO as of December 31, 2013 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2014 (in millions) AEP (c)(d)(e)(f) $ 1,835.0 $ 95.0 $ 42.8 $ (34.2 ) $ 81.0 $ 2,019.6 APCo (c)(f) 152.6 9.1 — (24.0 ) 10.7 148.4 I&M (c)(d)(f) 1,255.2 60.0 — (1.4 ) 28.7 1,342.5 OPCo (f) 1.3 0.1 — — — 1.4 PSO (c)(f) 22.9 1.8 — (0.7 ) 14.1 38.1 SWEPCo (c)(e)(f) 87.6 5.2 — (1.1 ) 2.7 94.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014 . (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 131.9 $ 102.9 $ 72.7 APCo 13.8 7.1 2.3 I&M 11.6 18.9 19.9 OPCo 8.8 6.9 5.0 PSO 8.8 3.1 4.2 SWEPCo 26.4 11.9 7.4 Years Ended December 31, Company 2015 2014 2013 (in millions) AEP $ 61.3 $ 44.5 $ 39.8 APCo 6.9 3.8 1.5 I&M 5.0 8.0 9.8 OPCo 4.8 4.4 10.1 PSO 5.0 1.8 2.3 SWEPCo 14.8 6.9 4.3
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 Registrant’s Share as of December 31, 2014 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP W.C. Beckjord Generating Station, Unit 6 (c) Coal 12.5 % $ — $ — $ — Conesville Generating Station, Unit 4 (a) Coal 43.5 % 335.7 2.4 65.9 J.M. Stuart Generating Station (b) Coal 26.0 % 552.7 11.5 205.8 Wm. H. Zimmer Generating Station (c) Coal 25.4 % 812.0 4.0 410.2 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 329.7 3.7 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 409.1 10.3 227.8 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Transmission NA (d) 81.8 0.8 49.2 Total $ 4,824.2 $ 189.7 $ 1,679.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 801.5 $ 119.9 $ 492.2 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 94.7 $ 2.6 $ 57.5 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 329.7 $ 3.7 $ 201.3 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 125.1 119.6 67.9 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 531.1 36.5 381.1 Turk Generating Plant (j) Coal 73.33 % 1,647.0 0.9 69.8 Total $ 2,632.9 $ 160.7 $ 720.1 (a) Operated by AGR. (b) Operated by The Dayton Power & Light Company, a non-affiliated company. (c) Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012. (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by TNC and various non-affiliated companies. (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. NA Not applicable.
Regulated Operation [Member]
Depreciation, Depletion and Amortization	AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 1.7% - 3.7% 31 - 132 Transmission 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 1.1% - 2.7% 25 - 87 Distribution 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 2.3% - 3.8% 11 - 75 Other 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 2.0% - 7.9% 5 - 75
Unregulated Operation [Member]
Depreciation, Depletion and Amortization	AEP 2015 2014 2013 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 2.6% - 3.3% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.5% 43 - 55 Other 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) NM NM (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Cost Reduction Programs (Tables

Cost Reduction Programs (Tables)	12 Months Ended
	Dec. 31, 2015
Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Appalachian Power Co [Member] | Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Appalachian Power Co [Member] | Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Indiana Michigan Power Co [Member] | Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Indiana Michigan Power Co [Member] | Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Ohio Power Co [Member] | Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Ohio Power Co [Member] | Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Public Service Co Of Oklahoma [Member] | Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Public Service Co Of Oklahoma [Member] | Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0
Southwestern Electric Power Co [Member] | Disposition Plant Severance [Member]
Remaining Accrual	Expense Remaining Balance as of Allocation from Incurred by Balance as of Company December 31, 2014 AEPSC Registrants Settled Adjustments December 31, 2015 (in millions) AEP $ 29.2 $ — $ 2.7 $ 22.6 $ — $ 9.3 APCo 9.3 — 0.9 7.0 (a) (0.1 ) 3.1 I&M 8.0 — 0.3 5.4 — 2.9 PSO 0.1 — 0.3 0.2 — 0.2 SWEPCo 0.1 — — 0.1 — — (a) Includes amounts received from affiliates for expenses related to jointly-owned plant.
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 29.2 APCo 7.1 I&M 8.2 OPCo 0.1 PSO 0.3 SWEPCo 0.3
Southwestern Electric Power Co [Member] | Sustainable Cost Reductions [Member]
Total Cost Incurred	Company Total Cost Incurred (in millions) AEP $ 7.7 APCo 0.3 I&M 0.4 OPCo 5.8 PSO (0.1 ) SWEPCo 1.0

Unaudited Quarterly Financial57

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Quarterly Financial Information [Table Text Block]	2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (a) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (a) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (b) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a) 1.29 0.88 1.06 0.95 2014 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 559.8 $ 389.9 $ 493.2 $ 190.9 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations 1.14 0.79 0.99 0.32 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b) 0.01 0.01 0.02 0.07 Total Basic Earnings per Share Attributable to AEP Common Shareholders (a) 1.15 0.80 1.01 0.39 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations 1.14 0.79 0.99 0.32 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (a)(b) 0.01 0.01 0.02 0.07 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (a) 1.15 0.80 1.01 0.39 (a) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (b) Relates to sale of AEPRO (see Note 7 ). Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Appalachian Power Co [Member]
Schedule of Quarterly Financial Information [Table Text Block]	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Indiana Michigan Power Co [Member]
Schedule of Quarterly Financial Information [Table Text Block]	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Ohio Power Co [Member]
Schedule of Quarterly Financial Information [Table Text Block]	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Public Service Co Of Oklahoma [Member]
Schedule of Quarterly Financial Information [Table Text Block]	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).
Southwestern Electric Power Co [Member]
Schedule of Quarterly Financial Information [Table Text Block]	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (a) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2014 Total Revenues $ 4,497.5 $ 913.4 $ 641.8 $ 880.2 $ 301.4 $ 440.6 Operating Income 1,032.3 220.0 146.0 115.7 25.3 64.7 Income from Continuing Operations 558.3 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 561.0 101.8 87.1 60.8 8.4 23.0 June 30, 2014 Total Revenues $ 3,900.6 $ 694.7 $ 533.9 $ 786.1 $ 318.8 $ 449.3 Operating Income 760.7 110.7 57.1 114.0 48.9 78.8 Income from Continuing Operations 388.4 — — — — — Income from Discontinued Operations, Net of Tax 2.7 — — — — — Net Income 391.1 36.2 27.3 56.5 22.5 32.8 September 30, 2014 Total Revenues $ 4,161.4 $ 709.9 $ 542.9 $ 839.2 $ 417.0 $ 531.8 Operating Income 904.9 130.2 62.9 104.7 87.4 133.2 Income from Continuing Operations 484.2 — — — — — Income from Discontinued Operations, Net of Tax 10.2 — — — — — Net Income 494.4 48.8 26.6 54.1 45.1 74.6 December 31, 2014 Total Revenues $ 3,819.1 $ 735.1 $ 531.1 $ 871.4 $ 314.4 $ 424.7 Operating Income 429.5 (b) 107.3 39.2 99.1 27.2 46.0 Income from Continuing Operations 159.6 — — — — — Income from Discontinued Operations, Net of Tax 31.9 — — — — — Net Income 191.5 (b) 28.6 14.6 45.0 10.9 14.2 (a) Includes sale of AEPRO (see Note 7 ). (b) Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4 ).

Goodwill and Other Intangible58

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Changes in Carrying Amount of Goodwill	Corporate and Other Generation and Marketing AEP Consolidated (in millions) Balance as of December 31, 2013 $ 75.9 $ 15.4 $ 91.3 Impairment Losses — — — Balance as of December 31, 2014 75.9 15.4 91.3 Impairment Losses — — — Goodwill Written Off Related to Sale of AEPRO (38.8 ) (a) — (38.8 ) Balance as of December 31, 2015 $ 37.1 $ 15.4 $ 52.5 (a) The goodwill of $38.8 million related to AEPRO is included in Other Classes of Assets That Are Not Major as of December 31, 2014 in Note 7 . See “Dispositions” section of Note 7 for additional information.
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class	December 31, 2015 2014 Amortization Life Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (in years) (in millions) Acquired Customer Contracts 5 $ 58.3 $ 56.5 $ 58.3 $ 53.4

Organization and Summary of S59

Organization and Summary of Significant Accounting Policies (Details) $ / shares in Units, $ in Millions		3 Months Ended													12 Months Ended
		Dec. 31, 2015USD ($)$ / sharesMW		Sep. 30, 2015USD ($)$ / shares		Jun. 30, 2015USD ($)$ / shares		Mar. 31, 2015USD ($)$ / shares		Dec. 31, 2014USD ($)$ / shares		Sep. 30, 2014USD ($)$ / shares	Jun. 30, 2014USD ($)$ / shares	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2015USD ($)plant$ / sharesMWshares	Dec. 31, 2014USD ($)$ / sharesshares		Dec. 31, 2013USD ($)$ / sharesshares	Dec. 31, 2012USD ($)
Assets
Current Assets		$ 4,072.4								$ 4,478.1					$ 4,072.4	$ 4,478.1
Property, Plant and Equipment, Net		46,133.2								43,635.1	[1]				46,133.2	43,635.1	[1]
Other Noncurrent Assets		11,477.5								11,431.4					11,477.5	11,431.4
TOTAL ASSETS		61,683.1								59,544.6					61,683.1	59,544.6		$ 56,321
Liabilities and Equity
Long-term Debt		19,572.7								18,512.4	[2],[3]				19,572.7	18,512.4	[2],[3]
Other Current Liabilities		1,305.1								1,204.7					1,305.1	1,204.7
Other Liabilities, Noncurrent		890.6								895.8					890.6	895.8
Equity		17,904.9								16,824.5					17,904.9	16,824.5		16,085.6	$ 15,237.5
TOTAL LIABILITIES AND EQUITY		61,683.1								59,544.6					61,683.1	59,544.6
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 205.2		$ 511.8		$ 431.4		$ 620.2		$ 159.6		$ 484.2	$ 388.4	$ 558.3	1,768.6	1,590.5		1,473.9
Net Income (Loss) Attributable to Noncontrolling Interests															5.2	4.2		3.7
Income (Loss) from Continuing Operations Attributable to Parent															$ 1,763.4	$ 1,586.3		$ 1,470.2
Weighted Average Number of Basic AEP Common Shares Outstanding | shares															490,340,522	488,592,997		486,619,555
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares		$ 0.41	[4]	$ 1.04	[4]	$ 0.88	[4]	$ 1.27	[4]	$ 0.32		$ 0.99	$ 0.79	$ 1.14	$ 3.59	$ 3.24		$ 3.02
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding | shares															490,574,568	488,899,840		487,040,956
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares		$ 0.41	[4]	$ 1.04	[4]	$ 0.88	[4]	$ 1.27	[4]	$ 0.32		$ 0.99	$ 0.79	$ 1.14	$ 3.59	$ 3.24		$ 3.02
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															$ 1,674.3	$ 1,573.7		$ 1,441.4
Amortization of Certain Securitized Assets															318.9	310.4		248.2
Amortization of Regulatory Assets and Liabilities															16.5	13.5		22.9
Utilities Operating Expense, Depreciation and Amortization															2,009.7	1,897.6		1,712.5
Cash Paid (Received) for:
Interest Paid, Net															857.2	838.5		882.1
Income Taxes Paid, Net															120.2	117.3		(54.8)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															150.2	135.1		181.6
Construction Expenditures Included in Current Liabilities as of December 31,															741.4	559.3		492.4
Construction Expenditures Included in Noncurrent Liabilities as of December 31,															51.6	0		0
Construction Expenditures Included in Noncurrent Assets as of December 31,															10.5	0		0
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,															37.9	44.5		0
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage															2.2	3.4		4.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															3,436.6	2,067		3,206.6
Repayments of Long-term Debt															$ 2,397.9	$ 1,777.4		$ 2,595.4
Antidilutive Shares Outstanding | shares															0	0		0
Aggregate Power Participation Ratio		43.47%													43.47%
Ohio Valley Electric Corporation [Member]
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)	[5]														$ 0.1	$ 24		$ 20.9
AEP Consolidated Expenses - Purchased Electricity for Resale:
Ohio Valley Electric Corporation (43.47% Owned)															$ 241.7	268.5		289.2
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
AEP's Ownership in OVEC		43.47%													43.47%
AEP's Investment in OVEC		$ 4.4													$ 4.4
Supplemental Agreement During the Period Between Parties to Interconnection Agreement and OVEC															241.7	268.5		289.2
Ohio Valley Electric Corporation [Member] | Environmental Project [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Capital Expenditures Authorized		1,300													$ 1,300
Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Appalachian Power Co [Member]
Assets
Current Assets		627.9								$ 678.5					$ 627.9	678.5
Property, Plant and Equipment, Net		9,424.4								9,181.7					9,424.4	9,181.7
Other Noncurrent Assets		1,596								1,350.6					1,596	1,350.6
TOTAL ASSETS		11,648.3								11,210.8					11,648.3	11,210.8
Liabilities and Equity
Long-term Debt		3,930.7								3,958.7					3,930.7	3,958.7
Other Current Liabilities		153.4								145					153.4	145
Other Liabilities, Noncurrent		57.7								54.2					57.7	54.2
Equity		3,475								3,366.9					3,475	3,366.9		3,229.4	3,052.6
TOTAL LIABILITIES AND EQUITY		11,648.3								11,210.8					11,648.3	11,210.8
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		$ 0		$ 0		$ 0		0		$ 0	$ 0	$ 0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															385.6	383.3		334.2
Amortization of Certain Securitized Assets															0	0		0
Amortization of Regulatory Assets and Liabilities															3.2	17.6		8.4
Utilities Operating Expense, Depreciation and Amortization															388.8	400.9		342.6
Cash Paid (Received) for:
Interest Paid, Net															196.7	196.7		184.6
Income Taxes Paid, Net															30.4	15.9		(27.8)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															31.8	4.9		4.4
Construction Expenditures Included in Current Liabilities as of December 31,															90.4	72		50.8
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															726.3	394.2		444.4
Repayments of Long-term Debt															$ 672.6	612.7		345
Aggregate Power Participation Ratio		43.47%													43.47%
Appalachian Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Indiana Michigan Power Co [Member]
Assets
Current Assets		$ 455.3								476.5					$ 455.3	476.5
Property, Plant and Equipment, Net		5,203.5								5,416.4					5,203.5	5,416.4
Other Noncurrent Assets		3,051.6								2,764.6					3,051.6	2,764.6
TOTAL ASSETS		8,710.4								8,657.5					8,710.4	8,657.5
Liabilities and Equity
Long-term Debt		2,000								2,019.6					2,000	2,019.6
Other Current Liabilities		142.1								150.6					142.1	150.6
Other Liabilities, Noncurrent		119.4								162.2					119.4	162.2
Equity		2,036.4								1,954					2,036.4	1,954		1,922.2	1,803.8
TOTAL LIABILITIES AND EQUITY		8,710.4								8,657.5					8,710.4	8,657.5
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		0		0		0		0		0	0	0
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)															78.8	94.4		122.3
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															193.5	199.3		175.8
Amortization of Certain Securitized Assets															0	0		0
Amortization of Regulatory Assets and Liabilities															4.9	0.9		1.9
Utilities Operating Expense, Depreciation and Amortization															198.4	200.2		177.7
Cash Paid (Received) for:
Interest Paid, Net															84.5	81.6		90.1
Income Taxes Paid, Net															21.2	(10.2)		(31.3)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															3	16.4		114.1
Construction Expenditures Included in Current Liabilities as of December 31,															95.8	66.1		85.4
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,															37.9	44.5		0
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage															2.2	3.4		4.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															310.7	205.6		348.9
Repayments of Long-term Debt															$ 332.1	218.5		370.3
Aggregate Power Participation Ratio		43.47%													43.47%
Indiana Michigan Power Co [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent		$ 21.5								26.2					$ 21.5	26.2
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent		0								0					$ 0	0
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Ohio Power Co [Member]
Assets
Current Assets		573.2								736.8					$ 573.2	736.8
Property, Plant and Equipment, Net		5,054.7								4,763.6					5,054.7	4,763.6
Other Noncurrent Assets		1,510								1,760.2					1,510	1,760.2
TOTAL ASSETS		7,137.9								7,260.6					7,137.9	7,260.6
Liabilities and Equity
Long-term Debt		2,157.7								2,286.8					2,157.7	2,286.8
Other Current Liabilities		154.3								179.1					154.3	179.1
Other Liabilities, Noncurrent		30.7								25.5					30.7	25.5
Equity		1,986.6								1,980.2					1,986.6	1,980.2		1,625.3	4,525.7
TOTAL LIABILITIES AND EQUITY		7,137.9								7,260.6					7,137.9	7,260.6
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		0		0		0		0		0		0	0	0
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)															0	0		18.1
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															184.4	188.3		358
Amortization of Certain Securitized Assets															43.3	43.5		20
Amortization of Regulatory Assets and Liabilities															(10.2)	(18.1)		4.6
Utilities Operating Expense, Depreciation and Amortization															217.5	213.7		382.6
Cash Paid (Received) for:
Interest Paid, Net															121.6	132.4		195.7
Income Taxes Paid, Net															26.1	44		93.3
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															2.7	4.8		7.7
Construction Expenditures Included in Current Liabilities as of December 31,															34.3	43.4		92.3
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															0	0		1,378.3
Notes Receivable - Affiliated		$ 32.3								32.3					32.3	32.3
Repayments of Long-term Debt															$ 131.5	438.6		1,196
Aggregate Power Participation Ratio		43.47%													43.47%
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
AEP's Ownership in OVEC		4.30%													4.30%
AEP's Investment in OVEC		$ 0.4													$ 0.4
Ohio Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Ohio Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Ohio Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Ohio Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Public Service Co Of Oklahoma [Member]
Assets
Current Assets		245.4								191.7					$ 245.4	191.7
Property, Plant and Equipment, Net		3,693.2								3,440.6					3,693.2	3,440.6
Other Noncurrent Assets		231.8								176.9					231.8	176.9
TOTAL ASSETS		4,170.4								3,809.2					4,170.4	3,809.2
Liabilities and Equity
Long-term Debt		1,286.1								1,036.7					1,286.1	1,036.7
Other Current Liabilities		64.4								58.9					64.4	58.9
Other Liabilities, Noncurrent		13.7								13.6					13.7	13.6
Equity		1,119.9								1,028.2					1,119.9	1,028.2		942.1	916.2
TOTAL LIABILITIES AND EQUITY		4,170.4								3,809.2					4,170.4	3,809.2
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		0		0		0		0		0		0	0	0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															108.6	99.7		94.6
Amortization of Certain Securitized Assets															0	0		0
Amortization of Regulatory Assets and Liabilities															8.9	1.3		1.1
Utilities Operating Expense, Depreciation and Amortization															117.5	101		95.7
Cash Paid (Received) for:
Interest Paid, Net															54.8	52.8		51.4
Income Taxes Paid, Net															7.9	(21.2)		8.7
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															3.6	2.3		5.8
Construction Expenditures Included in Current Liabilities as of December 31,															47.4	38.6		63.6
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															248.8	75		49.7
Repayments of Long-term Debt															$ 0.4	34.1		0.4
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Southwestern Electric Power Co [Member]
Assets
Current Assets		335.3								429.2					$ 335.3	429.2
Property, Plant and Equipment, Net		6,321.1								5,907.3					6,321.1	5,907.3
Other Noncurrent Assets		491.6								472.3					491.6	472.3
TOTAL ASSETS		7,148								6,808.8					7,148	6,808.8
Liabilities and Equity
Long-term Debt		2,273.5								2,132.4					2,273.5	2,132.4
Other Current Liabilities		110.7								104.5					110.7	104.5
Other Liabilities, Noncurrent		49.3								47.3					49.3	47.3
Equity		2,169.7								2,097.2					2,169.7	2,097.2		2,055.9	$ 2,021.5
TOTAL LIABILITIES AND EQUITY		7,148								6,808.8					7,148	6,808.8
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		$ 0		$ 0		$ 0		$ 0		$ 0	$ 0	$ 0
Net Income (Loss) Attributable to Noncontrolling Interests															3.7	4.2		4
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment															190.7	183.2		177.3
Amortization of Certain Securitized Assets															0	0		0
Amortization of Regulatory Assets and Liabilities															1.3	1.9		1.9
Utilities Operating Expense, Depreciation and Amortization															192	185.1		179.2
Cash Paid (Received) for:
Interest Paid, Net															112.6	116.9		120.4
Income Taxes Paid, Net															15.4	(152.2)		(35.4)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred															7.4	4.1		9.4
Construction Expenditures Included in Current Liabilities as of December 31,															92.9	94.3		63.2
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt															445.9	99.4		0
Repayments of Long-term Debt															$ 306.8	$ 3.3		$ 3.3
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															25.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															59.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation															15.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															1.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation															65.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation															33.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation															2.00%
Ohio Valley Electric Corporation [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Approximate OVEC Generating Capacity (In MWs) | MW		2,400													2,400
Number of OVEC Generating Plants | plant															2
Number of Plants Operating with Environmental Controls | plant															2
Ohio Valley Electric Corporation [Member] | Environmental Project [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Capital Expenditures Authorized		$ 1,300													$ 1,300
Restricted Stock Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares | shares															300,000	300,000		400,000
Dilutive Securities, Effect on Basic Earnings Per Share | $ / shares															$ 0	$ 0		$ 0
[1]	Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
[3]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[4]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[5]	AEP did not ship coal to OVEC in 2015.

New Accounting Pronouncements60

New Accounting Pronouncements (Details) - Adjustments for New Accounting Pronouncement [Member] $ in Millions	12 Months Ended
	Dec. 31, 2014USD ($)
Debt Issuance Cost	$ 88.5
Appalachian Power Co [Member]
Debt Issuance Cost	21.6
Indiana Michigan Power Co [Member]
Debt Issuance Cost	7.8
Ohio Power Co [Member]
Debt Issuance Cost	10.3
Public Service Co Of Oklahoma [Member]
Debt Issuance Cost	4.3
Southwestern Electric Power Co [Member]
Debt Issuance Cost	$ 8.1

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	$ (103.1)	$ (115.2)	$ (337)
Change in Fair Value Recognized in AOCI	(20.7)	(7.8)	192.2
Amounts Reclassified from AOCI	(9.3)	19.9	24.4
Net Current Period Other Comprehensive Income	(30)	12.1	216.6
Pension and OPEB Adjustment Related to Mitchell Plant	6		5.2
Ending Balance in AOCI	(127.1)	(103.1)	(115.2)
Commodity
Vertically Integrated Utilities Revenues	9,069.9	9,396.8	9,346.6
Generation & Marketing Revenues	124.6	44.9	(20.2)
Purchased Electricity for Resale	2,760.1	2,085.9	1,490.8
Other Operation Expense	2,703.9	2,766.6	2,448.4
Maintenance Expense	1,325.3	1,328	1,163.2
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	2,009.7	1,897.6	1,712.5
Interest Expense	873.9	868	890
Income Tax (Expense) Credit	(919.6)	(902.6)	(677.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(9.3)	19.9	24.4
Pension and OPEB
Income Tax (Expense) Credit	(919.6)	(902.6)	(677.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(9.3)	19.9	24.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(9.3)	19.9	24.4
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	(10.5)	15.1	2.5
Commodity
Subtotal - Commodity	(16.1)	23.3	3.9
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(16.1)	23.3	3.9
Reclassifications from AOCI, before Income Tax (Expense) Credit	(16.1)	23.3	3.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(10.5)	15.1	2.5
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(16.1)	23.3	3.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(10.5)	15.1	2.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(10.5)	15.1	2.5
Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	7.7	6.8	4.2
Change in Fair Value Recognized in AOCI	(0.6)	0.9	2.6
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	(0.6)	0.9	2.6
Pension and OPEB Adjustment Related to Mitchell Plant	0		0
Ending Balance in AOCI	7.1	7.7	6.8
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	1.2	4.8	21.9
Commodity
Subtotal - Commodity	1.8	7.4	33.7
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	1.8	7.4	33.7
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.8	7.4	33.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(19.5)	(20.6)	(21)
Amortization of Actuarial Gain (Loss)	21.3	28	54.7
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.8	7.4	33.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	138.7	133.9	112
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	1.2	4.8	21.9
Net Current Period Other Comprehensive Income	1.2	4.8	21.9
Pension and OPEB Adjustment Related to Mitchell Plant	0		0
Ending Balance in AOCI	139.9	138.7	133.9
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.2	4.8	21.9
Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(232)	(233.1)	(414.9)
Change in Fair Value Recognized in AOCI	(25.7)	1.1	176.6
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	(25.7)	1.1	176.6
Pension and OPEB Adjustment Related to Mitchell Plant	6		5.2
Ending Balance in AOCI	(251.7)	(232)	(233.1)
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income	(30)	12.1	216.6
Pension and OPEB Adjustment Related to Mitchell Plant	6		5.2
Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	1.6	0.2	(8.1)
Change in Fair Value Recognized in AOCI	5.6	(9.8)	10.4
Amounts Reclassified from AOCI	(12.4)	11.2	(2.1)
Net Current Period Other Comprehensive Income	(6.8)	1.4	8.3
Pension and OPEB Adjustment Related to Mitchell Plant	0		0
Ending Balance in AOCI	(5.2)	1.6	0.2
Commodity
Subtotal - Commodity	(19)	17.2	(3.2)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(19)	17.2	(3.2)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(19)	17.2	(3.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(12.4)	11.2	(2.1)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(19)	17.2	(3.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(12.4)	11.2	(2.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(12.4)	11.2	(2.1)
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(19.1)	(23)	(30.2)
Change in Fair Value Recognized in AOCI	0	0	2.6
Amounts Reclassified from AOCI	1.9	3.9	4.6
Net Current Period Other Comprehensive Income	1.9	3.9	7.2
Pension and OPEB Adjustment Related to Mitchell Plant	0		0
Ending Balance in AOCI	(17.2)	(19.1)	(23)
Commodity
Subtotal - Commodity	2.9	6.1	7.1
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	2.9	6.1	7.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	2.9	6.1	7.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.9	3.9	4.6
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	2.9	6.1	7.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.9	3.9	4.6
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.9	3.9	4.6
Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(5.6)	8.2	1.4
Pension and OPEB
Income Tax (Expense) Credit	(5.6)	8.2	1.4
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	0.6	2.6	11.8
Pension and OPEB
Income Tax (Expense) Credit	0.6	2.6	11.8
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Vertically Integrated Utilities Revenues	0	0	(1.1)
Generation & Marketing Revenues	(48.1)	59.1	(9.7)
Purchased Electricity for Resale	29.1	(39.1)	7.6
Regulatory Assets/(Liabilities), Net	0	(2.8)	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	2.9	6.1	7.1
Appalachian Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5	2.9	(29.9)
Change in Fair Value Recognized in AOCI	(5.7)	4.4	30.4
Amounts Reclassified from AOCI	(2.1)	(2.3)	2.4
Net Current Period Other Comprehensive Income	(7.8)	2.1	32.8
Ending Balance in AOCI	(2.8)	5	2.9
Commodity
Vertically Integrated Utilities Revenues	2,805.6	2,899.4	3,059.6
Generation & Marketing Revenues	10.1	9.2	10.3
Purchased Electricity for Resale	395.2	456.6	232.7
Other Operation Expense	405.4	427.7	312
Maintenance Expense	263.3	259.3	273.2
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	388.8	400.9	342.6
Interest Expense	192.3	209.6	193
Income Tax (Expense) Credit	(194.3)	(154.9)	(132.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(2.1)	(2.3)	2.4
Pension and OPEB
Income Tax (Expense) Credit	(194.3)	(154.9)	(132.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(2.1)	(2.3)	2.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(2.1)	(2.3)	2.4
Appalachian Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	(0.3)	(1)	1
Commodity
Subtotal - Commodity	(0.4)	(1.5)	1.5
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(0.4)	(1.5)	1.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	(1.5)	1.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(1)	1
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	(1.5)	1.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(1)	1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(1)	1
Appalachian Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	(1.8)	(1.3)	1.4
Commodity
Subtotal - Commodity	(2.8)	(2)	2.2
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(2.8)	(2)	2.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.8)	(2)	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(5.1)	(5.1)	(5.1)
Amortization of Actuarial Gain (Loss)	2.3	3.1	7.3
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.8)	(2)	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Appalachian Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	19.2	20.5	19.1
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	(1.8)	(1.3)	1.4
Net Current Period Other Comprehensive Income	(1.8)	(1.3)	1.4
Ending Balance in AOCI	17.4	19.2	20.5
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.8)	(1.3)	1.4
Appalachian Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(18.1)	(20.8)	(50.5)
Change in Fair Value Recognized in AOCI	(5.7)	2.7	29.7
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	(5.7)	2.7	29.7
Ending Balance in AOCI	(23.8)	(18.1)	(20.8)
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income	(7.8)	2.1	32.8
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0.1	(0.6)
Change in Fair Value Recognized in AOCI	0	1.7	0.7
Amounts Reclassified from AOCI	0	(1.8)	0
Net Current Period Other Comprehensive Income	0	(0.1)	0.7
Ending Balance in AOCI	0	0	0.1
Commodity
Subtotal - Commodity	0	(2.7)	0
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	(2.7)	0
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(2.7)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.8)	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(2.7)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.8)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.8)	0
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3.9	3.1	2.1
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	(0.3)	0.8	1
Net Current Period Other Comprehensive Income	(0.3)	0.8	1
Ending Balance in AOCI	3.6	3.9	3.1
Commodity
Subtotal - Commodity	(0.4)	1.2	1.5
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(0.4)	1.2	1.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	1.2	1.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	0.8	1
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.4)	1.2	1.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	0.8	1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	0.8	1
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(0.1)	(0.5)	0.5
Pension and OPEB
Income Tax (Expense) Credit	(0.1)	(0.5)	0.5
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(1)	(0.7)	0.8
Pension and OPEB
Income Tax (Expense) Credit	(1)	(0.7)	0.8
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Vertically Integrated Utilities Revenues	0	0	(0.1)
Purchased Electricity for Resale	0	(0.5)	0.1
Regulatory Assets/(Liabilities), Net	0	(2.2)	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	(0.4)	1.2	1.5
Indiana Michigan Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(14.3)	(15.5)	(28.9)
Change in Fair Value Recognized in AOCI	(3.5)	0.6	11.3
Amounts Reclassified from AOCI	1.1	0.6	2.1
Net Current Period Other Comprehensive Income	(2.4)	1.2	13.4
Ending Balance in AOCI	(16.7)	(14.3)	(15.5)
Commodity
Vertically Integrated Utilities Revenues	2,073.3	2,149.1	2,022.3
Generation & Marketing Revenues	6.7	2	2.9
Purchased Electricity for Resale	195.8	96.8	151.4
Other Operation Expense	553.4	586	564
Maintenance Expense	212	228.5	195.9
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	198.4	200.2	177.7
Interest Expense	90.2	93.5	97.7
Income Tax (Expense) Credit	(96.1)	(79.6)	(75.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.6	2.1
Pension and OPEB
Income Tax (Expense) Credit	(96.1)	(79.6)	(75.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.6	2.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.6	2.1
Indiana Michigan Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	1.1	0.4	1.4
Commodity
Subtotal - Commodity	1.7	0.6	2.2
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	1.7	0.6	2.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	0.6	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.4	1.4
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	0.6	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.4	1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	0.4	1.4
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	0	0.2	0.7
Commodity
Subtotal - Commodity	0	0.3	1.1
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	0.3	1.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0.3	1.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(0.9)	(0.8)	(0.8)
Amortization of Actuarial Gain (Loss)	0.9	1.1	1.9
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0.3	1.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5.1	4.9	4.2
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	0	0.2	0.7
Net Current Period Other Comprehensive Income	0	0.2	0.7
Ending Balance in AOCI	5.1	5.1	4.9
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0.2	0.7
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(5)	(4.5)	(13)
Change in Fair Value Recognized in AOCI	(3.5)	(0.5)	8.5
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	(3.5)	(0.5)	8.5
Ending Balance in AOCI	(8.5)	(5)	(4.5)
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income		1.2	13.4
Indiana Michigan Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0.1	(0.4)
Change in Fair Value Recognized in AOCI	0	1.1	0.5
Amounts Reclassified from AOCI	0	(1.2)	0
Net Current Period Other Comprehensive Income	0	(0.1)	0.5
Ending Balance in AOCI	0	0	0.1
Commodity
Subtotal - Commodity	0	(1.8)	0
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	(1.8)	0
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(1.8)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.2)	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(1.8)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.2)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(1.2)	0
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(14.4)	(16)	(19.7)
Change in Fair Value Recognized in AOCI	0	0	2.3
Amounts Reclassified from AOCI	1.1	1.6	1.4
Net Current Period Other Comprehensive Income	1.1	1.6	3.7
Ending Balance in AOCI	(13.3)	(14.4)	(16)
Commodity
Subtotal - Commodity	1.7	2.4	2.2
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	1.7	2.4	2.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	2.4	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	1.6	1.4
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	1.7	2.4	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	1.6	1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1.1	1.6	1.4
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	0.6	0.2	0.8
Pension and OPEB
Income Tax (Expense) Credit	0.6	0.2	0.8
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	0	0.1	0.4
Pension and OPEB
Income Tax (Expense) Credit	0	0.1	0.4
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Vertically Integrated Utilities Revenues	0	0	(0.2)
Purchased Electricity for Resale	0	(0.8)	0.2
Regulatory Assets/(Liabilities), Net	0	(1)	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	1.7	2.4	2.2
Ohio Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5.6	7.1	(165.7)
Change in Fair Value Recognized in AOCI	0	0	66.4
Amounts Reclassified from AOCI	(1.3)	(1.5)	11.2
Net Current Period Other Comprehensive Income	(1.3)	(1.5)	77.6
Distribution of Cook Coal Terminal to Parent			(2.7)
Distribution of OPCo Generation to Parent			(3,005.3)
Ending Balance in AOCI	4.3	5.6	7.1
Commodity
Generation & Marketing Revenues	8.5	6.8	15.4
Purchased Electricity for Resale	635	282	151.5
Other Operation Expense	630.3	594.8	708
Maintenance Expense	166.8	196	319.6
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	217.5	213.7	382.6
Interest Expense	127.8	128.3	182
Income Tax (Expense) Credit	(126.5)	(132.2)	(225.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	11.2
Pension and OPEB
Income Tax (Expense) Credit	(126.5)	(132.2)	(225.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	11.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	11.2
Ohio Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	(1.3)	(1.5)	(1.3)
Commodity
Subtotal - Commodity	(2)	(2.3)	(2)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(2)	(2.3)	(2)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2)	(2.3)	(2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	(1.3)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2)	(2.3)	(2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.5)	(1.3)
Ohio Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	0	0	12.5
Commodity
Subtotal - Commodity	0	0	19.2
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	0	19.2
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	19.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Pension and OPEB
Amortization of Prior Service Cost (Credit)	0	0	(5.8)
Amortization of Actuarial Gain (Loss)	0	0	25
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	19.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Ohio Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	58.4	58.4	45.9
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	0	0	12.5
Net Current Period Other Comprehensive Income	0	0	12.5
Distribution of Cook Coal Terminal to Parent			0
Distribution of OPCo Generation to Parent			0
Ending Balance in AOCI	58.4	58.4	58.4
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	12.5
Ohio Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(58.4)	(58.4)	(218.8)
Change in Fair Value Recognized in AOCI	0	0	65.4
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	0	0	65.4
Distribution of Cook Coal Terminal to Parent			(19.6)
Distribution of OPCo Generation to Parent			(75.4)
Ending Balance in AOCI	(58.4)	(58.4)	(58.4)
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income	(1.3)	(1.5)	77.6
Distribution of Cook Coal Terminal to Parent			19.6
Distribution of OPCo Generation to Parent			75.6
Ohio Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0.1	(0.9)
Change in Fair Value Recognized in AOCI	0	0	1
Amounts Reclassified from AOCI	0	(0.1)	0
Net Current Period Other Comprehensive Income	0	(0.1)	1
Distribution of Cook Coal Terminal to Parent			0
Distribution of OPCo Generation to Parent			0
Ending Balance in AOCI	0	0	0.1
Commodity
Subtotal - Commodity	0	(0.2)	0.1
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	(0.2)	0.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.2)	0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.2)	0.1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5.6	7	8.1
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	(1.3)	(1.4)	(1.3)
Net Current Period Other Comprehensive Income	(1.3)	(1.4)	(1.3)
Distribution of Cook Coal Terminal to Parent			0
Distribution of OPCo Generation to Parent			(0.2)
Ending Balance in AOCI	4.3	5.6	7
Commodity
Subtotal - Commodity	(2)	(2.1)	(2.1)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(2)	(2.1)	(2.1)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2)	(2.1)	(2.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.4)	(1.3)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2)	(2.1)	(2.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.4)	(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.3)	(1.4)	(1.3)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(0.7)	(0.8)	(0.7)
Pension and OPEB
Income Tax (Expense) Credit	(0.7)	(0.8)	(0.7)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	0	0	6.7
Pension and OPEB
Income Tax (Expense) Credit	0	0	6.7
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Vertically Integrated Utilities Revenues	0	0	(0.4)
Purchased Electricity for Resale	0	0	0.6
Other Operation Expense	0	0	(0.1)
Regulatory Assets/(Liabilities), Net	0	(0.2)	0
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	(2)	(2.1)	(2.1)
Public Service Co Of Oklahoma [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5	5.8	6.5
Change in Fair Value Recognized in AOCI	0	0	0.1
Amounts Reclassified from AOCI	(0.8)	(0.8)	(0.8)
Net Current Period Other Comprehensive Income	(0.8)	(0.8)	(0.7)
Ending Balance in AOCI	4.2	5	5.8
Commodity
Vertically Integrated Utilities Revenues	1,331.4	1,340.3	1,277.7
Generation & Marketing Revenues	3.2	4.2	3.6
Purchased Electricity for Resale	316.9	385	246.1
Other Operation Expense	268.4	262.8	225.5
Maintenance Expense	104.6	108	107.1
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	117.5	101	95.7
Interest Expense	58.6	54.6	53.1
Income Tax (Expense) Credit	(51.3)	(50.6)	(65.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.8)	(0.8)
Pension and OPEB
Income Tax (Expense) Credit	(51.3)	(50.6)	(65.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.8)	(0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.8)	(0.8)
Public Service Co Of Oklahoma [Member] | Cash Flow Hedges [Member]
Commodity
Subtotal - Commodity	(1.2)	(1.2)	(1.2)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(1.2)	(1.2)	(1.2)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.2)	(1.2)	(1.2)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.2)	(1.2)	(1.2)
Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income	(0.8)	(0.8)	(0.7)
Public Service Co Of Oklahoma [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0.1	0
Change in Fair Value Recognized in AOCI	0	0	0.1
Amounts Reclassified from AOCI	0	(0.1)	0
Net Current Period Other Comprehensive Income	0	(0.1)	0.1
Ending Balance in AOCI	0	0	0.1
Commodity
Subtotal - Commodity	0	(0.1)	0
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	(0.1)	0
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.1)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.1)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	(0.1)	0
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	5	5.7	6.5
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	(0.8)	(0.7)	(0.8)
Net Current Period Other Comprehensive Income	(0.8)	(0.7)	(0.8)
Ending Balance in AOCI	4.2	5	5.7
Commodity
Subtotal - Commodity	(1.2)	(1.1)	(1.2)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(1.2)	(1.1)	(1.2)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.2)	(1.1)	(1.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.7)	(0.8)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.2)	(1.1)	(1.2)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.7)	(0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.8)	(0.7)	(0.8)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(0.4)	(0.4)	(0.4)
Pension and OPEB
Income Tax (Expense) Credit	(0.4)	(0.4)	(0.4)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	0	(0.1)	0
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	(1.2)	(1.1)	(1.2)
Southwestern Electric Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(7.5)	(8.5)	(17.9)
Change in Fair Value Recognized in AOCI	(2.9)	(0.3)	7.5
Amounts Reclassified from AOCI	1	1.3	1.9
Net Current Period Other Comprehensive Income	(1.9)	1	9.4
Ending Balance in AOCI	(9.4)	(7.5)	(8.5)
Commodity
Vertically Integrated Utilities Revenues	1,762.3	1,817.9	1,742.6
Generation & Marketing Revenues	2	2.2	1.4
Purchased Electricity for Resale	110.6	178.1	170
Other Operation Expense	294.5	272.8	250.7
Maintenance Expense	155.9	149.2	129.7
Interest Rate and Foreign Currency
Depreciation and Amortization Expense	192	185.1	179.2
Interest Expense	119.9	126.1	130.3
Income Tax (Expense) Credit	(84.8)	(66.4)	(69.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1	1.3	1.9
Pension and OPEB
Income Tax (Expense) Credit	(84.8)	(66.4)	(69.5)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1	1.3	1.9
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1	1.3	1.9
Southwestern Electric Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	2	2.2	2.2
Commodity
Subtotal - Commodity	3.1	3.4	3.4
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	3.1	3.4	3.4
Reclassifications from AOCI, before Income Tax (Expense) Credit	3.1	3.4	3.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.2
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	3.1	3.4	3.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.2
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI	(1)	(0.9)	(0.3)
Commodity
Subtotal - Commodity	(1.5)	(1.4)	(0.4)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	(1.5)	(1.4)	(0.4)
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.5)	(1.4)	(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Pension and OPEB
Amortization of Prior Service Cost (Credit)	(1.9)	(1.9)	(1.8)
Amortization of Actuarial Gain (Loss)	0.4	0.5	1.4
Reclassifications from AOCI, before Income Tax (Expense) Credit	(1.5)	(1.4)	(0.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	3.6	4.5	4.8
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	(1)	(0.9)	(0.3)
Net Current Period Other Comprehensive Income	(1)	(0.9)	(0.3)
Ending Balance in AOCI	2.6	3.6	4.5
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1)	(0.9)	(0.3)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0.3	(7.1)
Change in Fair Value Recognized in AOCI	(2.9)	(0.3)	7.4
Amounts Reclassified from AOCI	0	0	0
Net Current Period Other Comprehensive Income	(2.9)	(0.3)	7.4
Ending Balance in AOCI	(2.9)	0	0.3
Interest Rate and Foreign Currency
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0
Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Net Current Period Other Comprehensive Income	(1.9)	1	9.4
Southwestern Electric Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	0	0	0
Change in Fair Value Recognized in AOCI	0	0	0.1
Amounts Reclassified from AOCI	0	0	(0.1)
Net Current Period Other Comprehensive Income	0	0	0
Ending Balance in AOCI	0	0	0
Commodity
Subtotal - Commodity	0	(0.1)	(0.1)
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	0	(0.1)	(0.1)
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.1)	(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	(0.1)
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	(0.1)	(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	(0.1)
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI	(11.1)	(13.3)	(15.6)
Change in Fair Value Recognized in AOCI	0	0	0
Amounts Reclassified from AOCI	2	2.2	2.3
Net Current Period Other Comprehensive Income	2	2.2	2.3
Ending Balance in AOCI	(9.1)	(11.1)	(13.3)
Commodity
Subtotal - Commodity	3.1	3.5	3.5
Interest Rate and Foreign Currency
Subtotal - Interest Rate and Foreign Currency	3.1	3.5	3.5
Reclassifications from AOCI, before Income Tax (Expense) Credit	3.1	3.5	3.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.3
Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit	3.1	3.5	3.5
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.3
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	2	2.2	2.3
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	1.1	1.2	1.2
Pension and OPEB
Income Tax (Expense) Credit	1.1	1.2	1.2
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency
Income Tax (Expense) Credit	(0.5)	(0.5)	(0.1)
Pension and OPEB
Income Tax (Expense) Credit	(0.5)	(0.5)	(0.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Other Operation Expense	0	0	(0.1)
Regulatory Assets/(Liabilities), Net	0	(0.1)	0
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency
Interest Expense	$ 3.1	$ 3.5	$ 3.5

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 23, 2016USD ($)	Jan. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / MWD$ / MWhMW	Dec. 31, 2014USD ($)
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets			$ 5,140.3	$ 4,263.7
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets			1,154.2	857.9
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets			804.3	536.2
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets			1,113	$ 1,318.9
Kentucky 2014 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Net Increase in Rates			70
Recommended Net Increase in Rates as Proposed in Stipulation Agreement			45
Recommended Increase in Rider Rates as Proposed in Stipulation Agreement			68
Recommended Decrease in Annual Base Rates as Proposed in Stipulation Agreement			23
Amount of Storm Costs Recommended for Recovery as Proposed in Stipulation Agreement			12
Amount of Off-System Sales Margins Included in the Annual Base Rates as Proposed in Stipulation Agreement			$ 15
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Shared with Customers as Proposed in Stipulation Agreement			75.00%
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Retained by KPCo as Proposed in Stipulation Agreement			25.00%
Approved Net Revenue Increase			$ 45
Amount of IGCC and Carbon Capture Costs Approved for Recovery			$ 2
Recovery Period of Approved IGCC and Carbon Capture Costs			25 years
Kentucky Fuel Adjustment Clause Review [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Regulatory Disallowance Resulting from a Commission Order			$ 36
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return On Equity			10.20%
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD			188.88
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD			34
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD			150
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh			3.50
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh			4
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh			1
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh			4
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)			32 months
Annual Retail Share of Fixed Fuel Costs			$ 90
Return on Equity Proposed in PPA Stipulation Agreement			10.38%
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement			100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement			50.00%
Future Commitment to Support the Development of a Large Solar Farm			$ 20
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return On Equity			10.20%
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD			188.88
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD			34
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD			150
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh			3.50
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh			4
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh			1
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh			4
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)			32 months
Annual Retail Share of Fixed Fuel Costs			$ 90
Return on Equity Proposed in PPA Stipulation Agreement			10.38%
Solar Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW			500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement			100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement			50.00%
Future Commitment to Support the Development of a Large Solar Farm			$ 20
Ohio Fuel Adjustment Clause Audit - 2009 [Member]
Public Utilities, General Disclosures [Line Items]
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO			65
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing			30
Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO			65
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing			30
Special Rate Mechanism For Ormet [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing			39
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement			10
Remaining Ormet Deferral Approved for Recovery			10
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009			64
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009			2
Special Rate Mechanism For Ormet [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing			39
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement			10
Remaining Ormet Deferral Approved for Recovery			10
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009			64
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009			2
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses			787
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses			787
West Virginia Base Rate Case - 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Approved Base Rate Increase			$ 99
Approved Return On Equity			9.75%
Amount of Annual Delayed Customer Billing to Residential Customers			$ 25
Approved Annual Vegetation Management Rider			45
Approved Recovery of Previously Recorded Regulatory Assets			89
West Virginia Base Rate Case - 2014 [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Base Rate Increase			$ 85
Approved Return On Equity			9.75%
Amount of Annual Delayed Customer Billing to Residential Customers			$ 22
Approved Annual Vegetation Management Rider			38
Approved Recovery of Previously Recorded Regulatory Assets			77
Virginia Regulatory Asset Proceeding - 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Amounts of Regulatory Assets Under Review in Separate Proceeding			10
Virginia Regulatory Asset Proceeding - 2015 [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amounts of Regulatory Assets Under Review in Separate Proceeding			10
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO			444
Noncurrent Regulatory Assets			359
Amount of Deferred Capacity Costs Collected from Customers			222
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO			444
Noncurrent Regulatory Assets			359
Amount of Deferred Capacity Costs Collected from Customers			222
Subsequent Event [Member] | Kingsport Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Base Rate Increase		$ 12
Requested Return on Equity		10.66%
Subsequent Event [Member] | West Virginia Base Rate Case - 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Of Recovery Requested Related To Delayed Billing Including Carrying Charges	$ 29
Subsequent Event [Member] | West Virginia Base Rate Case - 2014 [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Of Recovery Requested Related To Delayed Billing Including Carrying Charges	$ 26
Big Sandy Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant			$ 194
Amortization Period of Approved Regulatory Assets Related to Plant Retirement			25 years
Tanners Creek Plant, Units 1-4 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant			$ 265
Amortization Period of Approved Regulatory Assets Related to Plant Retirement			29 years
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized			$ 38
Tanners Creek Plant, Units 1-4 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant			$ 265
Amortization Period of Approved Regulatory Assets Related to Plant Retirement			29 years
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized			$ 38

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,903.9	$ 3,215.3
Remaining Contractual Construction Obligations		10,488.8
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		315.3	204.8
Remaining Contractual Construction Obligations		1,113.3
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		751.3	$ 472
Remaining Contractual Construction Obligations		854.1
Welsh Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		82
Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		$ 82
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Equity Ownership Interest in ETT		50.00%
AEP Share of ETT Cumulative Revenues Subject to Review		$ 433
Louisiana 2012 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2
Base Rate Increase per the Settlement Agreement		85
Fuel Rate Decrease per the Settlement Agreement		$ 83
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3
Louisiana 2012 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2
Base Rate Increase per the Settlement Agreement		85
Fuel Rate Decrease per the Settlement Agreement		$ 83
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3
Louisiana 2014 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5
Additional Requested Annual Increase		15
Requested Total Annual Increase		20
Amount Of Interim Rates Implemented In January 2015 As Approved In Partial Settlement Agreement		15
Louisiana 2014 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5
Additional Requested Annual Increase		15
Requested Total Annual Increase		20
Amount Of Interim Rates Implemented In January 2015 As Approved In Partial Settlement Agreement		15
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
Oklahoma 2014 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Fourteen Months of Revenues Beginning November 2014 Related to Advanced Metering Costs as Approved in Stipulation Agreement		24
2016 Revenues Related to Advanced Metering Costs as Approved in Stipulation Agreement		$ 27
Return on Common Equity for AFUDC and Factoring as Approved in Stipulation Agreement		9.85%
Oklahoma 2014 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Fourteen Months of Revenues Beginning November 2014 Related to Advanced Metering Costs as Approved in Stipulation Agreement		$ 24
2016 Revenues Related to Advanced Metering Costs as Approved in Stipulation Agreement		$ 27
Return on Common Equity for AFUDC and Factoring as Approved in Stipulation Agreement		9.85%
Oklahoma 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 137
Requested Base Rate Increase		89
Amount of Increased Depreciation Expense Requested		48
Amount of Increase Related to Environmental Controls		44
Amount of Requested Increase Related to Environmental Consumable Costs in the FAC		$ 4
Requested Return on Equity		10.50%
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects		$ 35
Property, Plant and Equipment, Net		93
Oklahoma 2015 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		137
Requested Base Rate Increase		89
Amount of Increased Depreciation Expense Requested		48
Amount of Increase Related to Environmental Controls		44
Amount of Requested Increase Related to Environmental Consumable Costs in the FAC		$ 4
Requested Return on Equity		10.50%
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects		$ 35
Property, Plant and Equipment, Net		93
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
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
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		900
Construction Work in Progress		343
Remaining Contractual Construction Obligations		40
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		900
Construction Work in Progress		343
Remaining Contractual Construction Obligations		40
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		578
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		578
Minimum [Member] | Oklahoma 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider		$ 10
Intervenor Recommended Return on Common Equity Range		8.75%
Intervenor Recommended Increase to Depreciation Expense		$ 23
Minimum [Member] | Oklahoma 2015 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider		$ 10
Intervenor Recommended Return on Common Equity Range		8.75%
Intervenor Recommended Increase to Depreciation Expense		$ 23
Maximum [Member] | Oklahoma 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider		$ 31
Intervenor Recommended Return on Common Equity Range		9.30%
Intervenor Recommended Increase to Depreciation Expense		$ 46
Maximum [Member] | Oklahoma 2015 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider		$ 31
Intervenor Recommended Return on Common Equity Range		9.30%
Intervenor Recommended Increase to Depreciation Expense		$ 46
Subsequent Event [Member] | Oklahoma 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Interim Annual Base Rate Increase	$ 75
Subsequent Event [Member] | Oklahoma 2015 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Interim Annual Base Rate Increase	$ 75
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		400
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		400
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 And Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		219
Construction Work in Progress		190
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 And Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		219
Construction Work in Progress		$ 190

Effects of Regulation (Details)

Effects of Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		$ 25,559.8	$ 25,727.5
Accumulated Depreciation		19,348.2	19,970.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,133.2	43,635.1	[1]
Other Inventory, Supplies, Gross		738.6	735.8
Noncurrent Regulatory Liabilities		3,736.1	3,892.4
Regulatory Assets
Current Regulatory Assets		115.2	126.6
Noncurrent Regulatory Assets		5,140.3	4,263.7
Regulatory Liabilities
Current Regulatory Liabilities		113.9	55.2
Noncurrent Regulatory Liabilities		3,736.1	3,892.4
Generating Units Probable of Abandonment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		358.6
Accumulated Depreciation		191.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		166.9
Other Inventory, Supplies, Gross		8.6
Noncurrent Regulatory Liabilities		31.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		31.2
Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		6,200.8	6,824
Accumulated Depreciation		3,407.6	3,823.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,424.4	9,181.7
Other Inventory, Supplies, Gross		127	131.3
Noncurrent Regulatory Liabilities		637.1	652.9
Regulatory Assets
Current Regulatory Assets		86.9	66.1
Noncurrent Regulatory Assets		1,154.2	857.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities		637.1	652.9
Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		3,841.7	3,741.9
Accumulated Depreciation		3,018	3,410.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,203.5	5,416.4
Other Inventory, Supplies, Gross		185.9	201.1
Noncurrent Regulatory Liabilities		1,076.2	1,199.7
Regulatory Assets
Current Regulatory Assets		11.6	0.8
Noncurrent Regulatory Assets		804.3	536.2
Regulatory Liabilities
Current Regulatory Liabilities		0.3	7.1
Noncurrent Regulatory Liabilities		1,076.2	1,199.7
Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Accumulated Depreciation		2,048.7	2,038.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,054.7	4,763.6
Other Inventory, Supplies, Gross		86.1	60.9
Noncurrent Regulatory Liabilities		514.2	514.7
Regulatory Assets
Noncurrent Regulatory Assets		1,113	1,318.9
Regulatory Liabilities
Current Regulatory Liabilities		27.6	46.3
Noncurrent Regulatory Liabilities		514.2	514.7
Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		1,302.6	1,264.7
Accumulated Depreciation		1,352.5	1,319.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,693.2	3,440.6
Other Inventory, Supplies, Gross		51.9	50.9
Noncurrent Regulatory Liabilities		335.1	334.5
Regulatory Assets
Current Regulatory Assets		0	35.7
Noncurrent Regulatory Assets		214.8	154.3
Regulatory Liabilities
Current Regulatory Liabilities		76.1	0
Noncurrent Regulatory Liabilities		335.1	334.5
Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		3,943.5	3,864.5
Accumulated Depreciation		2,602.3	2,503.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,321.1	5,907.3
Other Inventory, Supplies, Gross		71.5	73.7
Noncurrent Regulatory Liabilities		448.8	458.5
Regulatory Assets
Current Regulatory Assets		4.1	24
Noncurrent Regulatory Assets		415.8	393.6
Regulatory Liabilities
Current Regulatory Liabilities		8.4	0
Noncurrent Regulatory Liabilities		448.8	458.5
Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		3,695.3	3,840.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		3,695.3	3,840.4
Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		637.1	640.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities		637.1	640.9
Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		1,076.2	1,199.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,076.2	1,199.6
Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		473.4	479.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		473.4	479.1
Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		335.1	330.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		335.1	330.3
Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		448.8	458.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities		448.8	458.5
Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		40.8	52
Regulatory Liabilities
Noncurrent Regulatory Liabilities		40.8	52
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	12
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	12
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	0.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.1
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		40.8	35.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		40.8	35.6
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	4.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	4.2
Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		167.9	227.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		57.3	125.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		59.3	13.6
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.3	10.5
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		13.4	17.7
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		5.9	12.1
Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		4,972.4	4,036.4
Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,096.9	732.2
Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		745	522.6
Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,111.7	1,308.4
Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		201.4	136.6
Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		409.9	381.5
Acquisition of Valley Electric Membership Corporation [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	1.8
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		11.4	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.4	0
Remaining Refund Period		1 year
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 11.4	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.4	0
Remaining Refund Period		1 year
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 0	3.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	3.9
Advanced Metering Infrastructure Surcharge [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		21.2	43.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 21.2	43.7
Remaining Refund Period		5 years
Amos Plant Transfer Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2	1.4
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	2,656.5	2,660.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	2,656.5	2,660.3
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	612.9	617.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	612.9	617.3
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	350.6	378.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	350.6	378.5
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	422.3	423.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	422.3	423.2
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	275.5	275.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	275.5	275.4
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[2]	396.8	384.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[2]	396.8	384.3
Asset Retirement Obligation [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.4	4.4
Remaining Recovery Period		2 years
Asset Retirement Obligation - Arkansas, Louisiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.7	1.1
Base Load Purchase Power Contract [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	6.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	6.1
Base Plan Funding Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		1.3	1.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.3	1.4
Remaining Refund Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 4.9	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 4.9	0
Remaining Refund Period		2 years
Capacity Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.5	25.1
Remaining Recovery Period		1 year
Capacity Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.5	25.1
Remaining Recovery Period		1 year
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.3
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.2	0
Remaining Recovery Period		7 years
Carbon Capture and Storage Product Validation Facility [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	13.3
Carbon Capture and Storage Product Validation Facility [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.7	0
Remaining Recovery Period		5 years
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	13.3
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.7	0
Remaining Recovery Period		5 years
Consumer Rate Relief - West Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 2.9	2.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.9	2.6
Remaining Refund Period		1 year
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 26.8	38
Remaining Recovery Period		3 years
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 26.8	38
Remaining Recovery Period		3 years
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.7	6.6
Cook Plant, Unit 2 Baffle Bolts - Indiana [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.6	6.9
Remaining Recovery Period		23 years
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 29.1	55.2
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 0	7.1
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 27.6	46.3
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 84.8	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 0.3	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 76.1	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 8.4	0
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 38.9	121.2
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 27.3	60.7
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 7.5	0.8
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		$ 0	35.7
Remaining Recovery Period
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 4.1	24
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 304.5	377.5
Remaining Recovery Period		3 years
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 304.5	377.5
Remaining Recovery Period		3 years
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 76.3	5.4
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 59.6	5.4
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 4.1	0
Remaining Recovery Period		1 year
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 113.3	112.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 113.3	112.6
Remaining Refund Period		47 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 35	38.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 35	38.3
Remaining Refund Period		21 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 46.3	46.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46.3	46.9
Remaining Refund Period		26 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 8.5	9.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8.5	9.8
Remaining Refund Period		15 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 14.7	25.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 14.7	25.8
Remaining Refund Period		43 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 1	1.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1	1.3
Remaining Refund Period		43 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 0	0.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.1
Deferral of Major Generation Overhauls [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.7	1.3
Remaining Recovery Period		2 years
Deferred Asset Phase-In Rider [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 5.1	7.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 5.1	7.1
Remaining Refund Period		5 years
Deferred Cook Plant Life Cycle Management Project Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	2.2
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		4.2	1.2
Deferred Restructuring Costs - Louisiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.5	5.1
Remaining Recovery Period		3 years
Deferred Restructuring Costs - Michigan [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.2
Deferred Restructuring Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.5	6.5
Remaining Recovery Period		3 years
Deferred System Reliability Rider Expenses [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.9	8.3
Remaining Recovery Period		1 year
Deferred System Reliability Rider Expenses [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.9	8.3
Remaining Recovery Period		1 year
Deferred Wind Power Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 11.8	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.8	0
Remaining Refund Period		2 years
Deferred Wind Power Costs - Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 11.8	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.8	0
Remaining Refund Period		2 years
Deferred Wind Power Costs - Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 0	4.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	4.5
Distribution Investment Rider [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	9.9
Remaining Recovery Period		2 years
Distribution Investment Rider [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	9.9
Remaining Recovery Period		2 years
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 8	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8	0
Remaining Refund Period		2 years
Enhanced Service Reliability Plan [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	6.5
Environmental Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	3.3
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[3]	636.5	694.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	636.5	694.9
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[3]	636.5	694.9
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	636.5	694.9
Excess Earnings [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		10.6	11.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 10.6	11.1
Remaining Refund Period		38 years
Excess Earnings - Texas [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 2.7	2.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.7	2.8
Remaining Refund Period		38 years
Expanded Net Energy Charge - Coal Inventory [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	3.4
Expanded Net Energy Charge - Construction Surcharge [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	5.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	5.4
Expanded Net Energy Charge - Construction Surcharge [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	2.3
Felman Special Rate Mechanism - West Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	2.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	2.1
Generation Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.2	3.8
Remaining Recovery Period		3 years
Generation Recovery Rider Costs - Arkansas [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 1.5	1.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.5	1.7
Remaining Refund Period		2 years
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.3	0
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.5	15.9
Remaining Recovery Period		2 years
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.5	15.9
Remaining Recovery Period		2 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1,385.3	1,268.3
Remaining Recovery Period		52 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 441.7	381.7
Remaining Recovery Period		25 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 246.8	255
Remaining Recovery Period		29 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 129	137.5
Remaining Recovery Period		31 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.1	1.9
Remaining Recovery Period		35 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 271.9	254.9
Remaining Recovery Period		31 years
Integrated Gasification Combined Cycle Preconstruction Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	10.8
Integrated Gasification Combined Cycle Preconstruction Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.9	0
Remaining Recovery Period		25 years
Integrated Gasification Combined Cycle Preconstruction Costs - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	10.8
Integrated Gasification Combined Cycle Preconstruction Costs - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.6	0
Remaining Recovery Period		5 years
Litigation Settlement [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.6	9.5
Remaining Recovery Period		10 years
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 37.4	58.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 37.4	58.2
Remaining Refund Period		3 years
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 37.4	58.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 37.4	58.2
Remaining Refund Period		3 years
Low Income Customers/Economic Recovery [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 1	1.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1	1.3
Remaining Refund Period		1 year
Mitchell Plant Transfer [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.3	0
Remaining Recovery Period		25 years
Northeastern Station Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member] | Generating Units Probable of Abandonment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		$ 182.5
Accumulated Depreciation		93.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		89.4
Other Inventory, Supplies, Gross		4
Noncurrent Regulatory Liabilities		$ 11.3
Expected Retirement Date		2,016
Remaining Recovery Period, Plant Depreciation		25 years
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.3
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	19.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	19.4
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	19.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	19.4
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.8	0
Remaining Recovery Period		2 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 358.7	422.1
Remaining Recovery Period		3 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 358.7	422.1
Remaining Recovery Period		3 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.5	35.1
Remaining Recovery Period		2 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.5	35.1
Remaining Recovery Period		2 years
Ohio Economic Development Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 5	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 5	0
Remaining Refund Period		2 years
Ohio Economic Development Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	4.1
Ohio Transmission Cost Recovery Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	27.9
Remaining Recovery Period		1 year
Ohio Transmission Cost Recovery Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.3	27.9
Remaining Recovery Period		1 year
Ormet Special Rate Recovery Mechanism | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	10.5
Ormet Special Rate Recovery Mechanism | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	10.5
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		36.7	29.1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1	0.8
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.2	0.1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		68.5	53.6
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	0.1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.1	1.8
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.9	0
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.4	0.9
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.3	1.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		31.7	42.7
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	0.1
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	0.7
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.1	1.1
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.8	0.6
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		37.7	28.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		37.7	28.1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0.1	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.1	0
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		1.7	0.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.7	0.1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	0.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0.6	0.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.6	0.5
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		1.9	1.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.9	1.7
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		20.5	3.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		20.5	3.8
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0.2	16.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	16.8
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	0.1
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.1
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0.2	0.4
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.4
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Public Service Co Of Oklahoma [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		0	0.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.3
Partnership with Ohio Contribution [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.4	0.4
Remaining Recovery Period		3 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 1.5	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.5	0
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 13.1	9
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 33.3	62.4
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.6	16.6
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	29.1
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.8	9.2
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1	2.2
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.7	8.8
Peak Demand Reduction/Energy Efficiency - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.5	0.9
Remaining Recovery Period		2 years
PJM Expense [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.1	21.9
Remaining Recovery Period		2 years
PJM Expense - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.1	21.9
Remaining Recovery Period		2 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 59.8	0
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		32.7	0
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		27.1	0
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 58	0
Remaining Recovery Period		25 years
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 20.9	0
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9.3	0
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11.6	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 577.4	0
Remaining Recovery Period		29 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 86.5	0
Remaining Recovery Period		24 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 260.3	0
Remaining Recovery Period		29 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 42.6	39.2
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.6	17.8
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.7	10
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.3	6.1
Remaining Recovery Period		5 years
Provision for Regulatory Loss [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 40.6	35.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		40.6	35.2
Provision for Regulatory Loss [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		40.6	35.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		40.6	35.2
Rate Case Expense [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.2	0
Remaining Recovery Period		2 years
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.3	8.1
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.8	0
Remaining Recovery Period		3 years
Red Rock Generating Facility [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.3	9.5
Remaining Recovery Period		41 years
Red Rock Generating Facility [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.3	9.5
Remaining Recovery Period		41 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.1	2.5
Remaining Recovery Period		4 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.5	1.8
Remaining Recovery Period		4 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.1	3.7
Remaining Recovery Period		4 years
Regulatory Settlement [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 9	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 9	0
Remaining Refund Period		2 years
River Transportation Division Expenses [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 1.9	5.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.9	5.3
Remaining Refund Period		1 year
Rockport Plant Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.8	0.1
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.1	2.3
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[3]	43.4	43.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	43.4	43.5
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities	[3]	43.4	43.5
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3]	43.4	43.5
Storm Related Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		1.3	0
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.3	0
Remaining Refund Period		1 year
Storm Related Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 24.2	20.2
Storm Related Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.8	13
Remaining Recovery Period		3 years
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.2	100.4
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		12.3	16.6
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 94.6	26
Remaining Recovery Period		5 years
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.1	15.2
Remaining Recovery Period		1 year
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.4	0
Remaining Recovery Period		4 years
Storm Related Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.1
Storm Related Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.8	0
Remaining Recovery Period		1 year
Storm Related Costs - Virginia [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.8	13
Remaining Recovery Period		3 years
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	65.2
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 63.5	8.5
Remaining Recovery Period		5 years
Stranded Costs on Abandoned Plants [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.9	3.9
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 90.4	59.2
Remaining Recovery Period		12 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 35.8	0
Remaining Recovery Period		11 years
Transition Charges [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 46.5	46.8
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 46.5	46.8
Remaining Refund Period		12 years
Transmission Agreement Phase-In - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.7	2.9
Remaining Recovery Period		2 years
Transmission Cost Recovery Factor [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.9	15.4
Remaining Recovery Period		1 year
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 74.6	53.2
Remaining Recovery Period		2 years
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 74.6	53.2
Remaining Recovery Period		2 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 148.7	65.7
Remaining Recovery Period		30 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 101.5	11.1
Remaining Recovery Period		30 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12	13.3
Remaining Recovery Period		17 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.4	11.7
Remaining Recovery Period		23 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.8	8
Remaining Recovery Period		17 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6	7
Remaining Recovery Period		28 years
Uncollected Accounts - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.5	0
Remaining Recovery Period		5 years
United Mine Workers of America Pension Withdrawal [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 14.4	25.4
Remaining Recovery Period		10 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 33.8	92.2
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 33.8	92.2
Remaining Refund Period		17 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 8.4	19.7
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 8.4	19.7
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 7.1	19.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 7.1	19.6
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Noncurrent Regulatory Liabilities		$ 15.3	47.3
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 15.3	47.3
Remaining Refund Period		17 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.7	9.7
Remaining Recovery Period		2 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.6	4.1
Remaining Recovery Period		2 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.2	0.5
Remaining Recovery Period		2 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.5	1.1
Remaining Recovery Period		2 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 36.9	5.4
Remaining Recovery Period		6 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.5	2.9
Remaining Recovery Period		1 year
Vegetation Management Program - Louisiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	2.5
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	20.4
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	19.1
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 31.2	0
Remaining Recovery Period		6 years
Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member] | Generating Units Probable of Abandonment [Member]
Regulated Generating Units To Be Retired Before Or During 2016
Gross Investment		$ 176.1
Accumulated Depreciation		98.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		77.5
Other Inventory, Supplies, Gross		4.6
Noncurrent Regulatory Liabilities		$ 19.9
Expected Retirement Date		2,016
Remaining Recovery Period, Plant Depreciation		25 years
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 19.9
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 41.8	46.5
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.2	10.2
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.3	10.3
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.4	4.9
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.8	5.3
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.3	5.9
Remaining Recovery Period		9 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1,410.5	1,273.1
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 217.6	212.5
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 126.4	107.8
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 219.4	195.4
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 95.1	89.7
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 108.9	$ 99.9
Remaining Recovery Period		12 years
[1]	Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Relieved as removal costs are incurred.
[3]	Relieved when plant is decommissioned.

Commitments, Guarantees and C65

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Contractual Commitments
Less than 1 year		$ 2,419.6
For 2-3 years		2,874.2
For 4-5 years		2,160.7
After 5 years		3,034.3
Total Contractual Commitments		10,488.8
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		3,500
Disposal, Assessed Fees and Related Interest	[1]	265.6	$ 265.5
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit		23
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		124.6
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		476.7
Bilateral Letters of Credit	[2]	482.1
Bilateral Letters of Credit Cancelled		76
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		3,500
Letters of Credit Limit		1,200
Uncommitted Facility		225
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		115
Estimated Final Cost Mine Reclamation		58
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		65
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent		15
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		50
Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	2,038
For 2-3 years	[3]	2,442.7
For 4-5 years	[3]	1,723.6
After 5 years	[3]	1,072.6
Total Contractual Commitments	[3]	7,276.9
Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		203
For 2-3 years		431.5
For 4-5 years		437.1
After 5 years		1,961.7
Total Contractual Commitments		3,033.3
Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	178.6
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	178.6
Appalachian Power Co [Member]
Contractual Commitments
Less than 1 year		499.9
For 2-3 years		653.1
For 4-5 years		556.6
After 5 years		718.3
Total Contractual Commitments		2,427.9
Appalachian Power Co [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		229.7
Bilateral Letters of Credit	[2]	232.3
Bilateral Letters of Credit Cancelled		76
Appalachian Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	447.4
For 2-3 years	[3]	585.8
For 4-5 years	[3]	486.8
After 5 years	[3]	244.8
Total Contractual Commitments	[3]	1,764.8
Appalachian Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		33
For 2-3 years		67.3
For 4-5 years		69.8
After 5 years		473.5
Total Contractual Commitments		643.6
Appalachian Power Co [Member] | Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	19.5
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	19.5
Indiana Michigan Power Co [Member]
Contractual Commitments
Less than 1 year		511.1
For 2-3 years		580
For 4-5 years		488.2
After 5 years		900.3
Total Contractual Commitments		2,479.6
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Disposal, Assessed Fees and Related Interest	[1]	265.6	265.5
Indiana Michigan Power Co [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		77
Bilateral Letters of Credit		77.9
Indiana Michigan Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	394.2
For 2-3 years	[3]	349.9
For 4-5 years	[3]	252.2
After 5 years	[3]	286.4
Total Contractual Commitments	[3]	1,282.7
Indiana Michigan Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		108.1
For 2-3 years		230.1
For 4-5 years		236
After 5 years		613.9
Total Contractual Commitments		1,188.1
Indiana Michigan Power Co [Member] | Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	8.8
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	8.8
Ohio Power Co [Member]
Contractual Commitments
Less than 1 year		31.7
For 2-3 years		54.8
For 4-5 years		56.2
After 5 years		479.9
Total Contractual Commitments		622.6
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		4.2
Ohio Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		27
For 2-3 years		54.8
For 4-5 years		56.2
After 5 years		479.9
Total Contractual Commitments		617.9
Ohio Power Co [Member] | Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	4.7
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	4.7
Public Service Co Of Oklahoma [Member]
Contractual Commitments
Less than 1 year		209.1
For 2-3 years		269
For 4-5 years		223.7
After 5 years		411.5
Total Contractual Commitments		1,113.3
Public Service Co Of Oklahoma [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	123.7
For 2-3 years	[3]	86.8
For 4-5 years	[3]	41.8
After 5 years	[3]	41.8
Total Contractual Commitments	[3]	294.1
Public Service Co Of Oklahoma [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		83.6
For 2-3 years		182.2
For 4-5 years		181.9
After 5 years		369.7
Total Contractual Commitments		817.4
Public Service Co Of Oklahoma [Member] | Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	1.8
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	1.8
Southwestern Electric Power Co [Member]
Contractual Commitments
Less than 1 year		230.6
For 2-3 years		202.8
For 4-5 years		146.3
After 5 years		274.4
Total Contractual Commitments		854.1
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount		115
Estimated Final Cost Mine Reclamation		58
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs		65
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent		15
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		50
Southwestern Electric Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	198.5
For 2-3 years	[3]	136.8
For 4-5 years	[3]	78.6
After 5 years	[3]	69.8
Total Contractual Commitments	[3]	483.7
Southwestern Electric Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		27.3
For 2-3 years		66
For 4-5 years		67.7
After 5 years		204.6
Total Contractual Commitments		365.6
Southwestern Electric Power Co [Member] | Construction Contracts for Capital Assets [Member]
Contractual Commitments
Less than 1 year	[4]	4.8
For 2-3 years	[4]	0
For 4-5 years	[4]	0
After 5 years	[4]	0
Total Contractual Commitments	[4]	4.8
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		8
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		8
Decommissioning and Low Level Waste Accumulation Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5
Subsequent Decommissioning of the Spent Fuel Storage Facility		57
Amount Recovered in Rates for Decommissioning Costs		9	9	$ 10
Decommissioning Fund Investments, Fair Value		1,800	1,800
Decommissioning and Low Level Waste Accumulation Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5
Subsequent Decommissioning of the Spent Fuel Storage Facility		57
Amount Recovered in Rates for Decommissioning Costs		9	9	10
Decommissioning Fund Investments, Fair Value		1,800	1,800
Nuclear Incident Liability [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,800
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,700
Contingent Financial Obligation for Mutual Iinsurance		49
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,500
Commercially Available Insurance		375
Remainder of the Liability Provided by a Deferred Premium Assessment		127
Deferred Premium Assessment Annual Payment		19
Assessed Amount per Nuclear Incident		255
Annual Installments		38
Commercially Available Insurance for Catastrophic Nature		375
Liability Coverage Under the Price-Anderson Act		13,100
Nuclear Incident Liability [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		2,800
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,700
Contingent Financial Obligation for Mutual Iinsurance		49
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,500
Commercially Available Insurance		375
Remainder of the Liability Provided by a Deferred Premium Assessment		127
Deferred Premium Assessment Annual Payment		19
Assessed Amount per Nuclear Incident		255
Annual Installments		38
Commercially Available Insurance for Catastrophic Nature		375
Liability Coverage Under the Price-Anderson Act		13,100
Spent Nuclear Fuel Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		309	309
Recovery of Spent Nuclear Fuel Storage Costs		13	22	31
Current Amount Recoverable from the Federal Government		6
Noncurrent Amount Recoverable from the Federal Government		21
Spent Nuclear Fuel Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		309	309
Recovery of Spent Nuclear Fuel Storage Costs		13	$ 22	$ 31
Current Amount Recoverable from the Federal Government		6
Noncurrent Amount Recoverable from the Federal Government		21
Maximum [Member] | Wage and Hours Lawsuit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Range of Possible Loss		30
Maximum [Member] | Wage and Hours Lawsuit [Member] | Public Service Co Of Oklahoma [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Range of Possible Loss		$ 30
[1]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[2]	In January 2016, $76 million of bilateral letters of credit maturing in March 2016 were cancelled.
[3]	Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
[4]	Represents only capital assets for which there are signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

Dispositions and Impairments (D

Dispositions and Impairments (Details) - USD ($) $ in Millions		3 Months Ended									12 Months Ended
		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt											$ 92.7	$ 0	$ 0
Asset Impairments and Other Related Charges											0	0	226.4
Dispositions and Impairments [Abstract]
Property, Plant and Equipment - Net							$ 482					482
Total Assets from Discontinued Operations on the Balance Sheet							624.9					624.9
Long-term Debt							83.2					83.2
Obligations Under Capital Leases							189					189
Total Liabilities from Discontinued Operations on the Balance Sheet	[1]						434.8					434.8
Income Tax Expense												39	5.9
Total Income on Discontinued Operations as Presented on the Statements of Income		$ 265.5	[2]	$ 7.8	$ (0.1)	$ 10.5	31.9	$ 10.2	$ 2.7	$ 2.7	283.7	47.5	10.3
Corporate and Other [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Net Cash Proceeds from Sale of AEPRO											491
Cash Proceeds from Sale of AEPRO, Gross											539
Make Whole Premium on Extinguishment of Long-term Debt											32
Disposition of Business, Transaction Cost											16
Dispositions and Impairments [Abstract]
Accounts Receivable							90.6					90.6
Property, Plant and Equipment - Net							482.3					482.3
Other Classes of Assets That Are Not Major							52					52
Total Assets from Discontinued Operations on the Balance Sheet							624.9					624.9
Long-term Debt							83.2					83.2
Obligations Under Capital Leases							189					189
Other Classes of Liabilities That Are Not Major							162.6					162.6
Total Liabilities from Discontinued Operations on the Balance Sheet							434.8					434.8
Other Revenues											447.1	641.6	543.6
Other Operation Expense											321.3	459.5	455.7
Maintenance Expense											21.5	32.6	15.7
Depreciation and Amortization Expense											26.9	31.5	30.5
Taxes Other Than Income Taxes											10.6	14.2	10
Total Expenses											380.3	537.8	511.9
Other Expense											(16.9)	(17.1)	(15.5)
Pretax Income of Discontinued Operations											49.9	86.7	16.2
Income Tax Expense											19.4	39	5.9
Equity Earnings of Unconsolidated Subsidiaries											(0.1)	(0.2)	0
Income from Discontinued Operations of AEPRO											30.4	47.5	10.3
Gain on Sale of Discontinued Operations											240.1	0	0
Income Tax Expense (Benefit)											(13.2)	0	0
Gain on Sale of Discontinued Operations, Net of Tax											253.3	0	0
Total Income on Discontinued Operations as Presented on the Statements of Income											283.7	47.5	10.3
Vertically Integrated Utilities [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges													72.1
Dispositions and Impairments [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet							0					0
Total Liabilities from Discontinued Operations on the Balance Sheet							0					0
Total Income on Discontinued Operations as Presented on the Statements of Income											0	0	0
Vertically Integrated Utilities [Member] | Amos Plant Unit 3 [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Reduction to Proposed Transfer Price													83
Virginia Share of Reduced Price													39
Asset Impairments and Other Related Charges													39
Vertically Integrated Utilities [Member] | Big Sandy Plant Unit 2 FGD Project [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges													33
Generation and Marketing [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges													154.3
Dispositions and Impairments [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet							0					0
Total Liabilities from Discontinued Operations on the Balance Sheet							0					0
Total Income on Discontinued Operations as Presented on the Statements of Income											0	0	0
Generation and Marketing [Member] | Muskingum River Plant [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Payment on Sale of Muskingum River Plant											48
Gain on Sale of Muskingum River Plant											32
Generation and Marketing [Member] | Muskingum River Plant Unit 5 [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges													154
Asset Impairment on Related Material and Supplies Inventory													6
Appalachian Power Co [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt											92.7	0	0
Asset Impairments and Other Related Charges											0	0	39.3
Dispositions and Impairments [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income		0		0	0	0	0	0	0	0
Appalachian Power Co [Member] | Amos Plant Unit 3 [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Reduction to Proposed Transfer Price													83
Virginia Share of Reduced Price													39
Asset Impairments and Other Related Charges													39
Indiana Michigan Power Co [Member]
Dispositions and Impairments [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income		0		0	0	0	0	0	0	0
Public Service Co Of Oklahoma [Member]
Dispositions and Impairments [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income		0		0	0	0	0	0	0	0
Southwestern Electric Power Co [Member]
Dispositions and Impairments [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income		0		0	0	0	0	0	0	0
Ohio Power Co [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges											$ 0	$ 0	154.3
Dispositions and Impairments [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income		$ 0		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Ohio Power Co [Member] | Muskingum River Plant Unit 5 [Member]
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]
Asset Impairments and Other Related Charges													154
Asset Impairment on Related Material and Supplies Inventory													$ 6
[1]	Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Includes sale of AEPRO (see Note 7).

Benefit Plans 1 (Details)

Benefit Plans 1 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		$ 2,106.6	$ 2,131.3
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(890.6)	(895.8)
Appalachian Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		113.7	137.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(57.7)	(54.2)
Indiana Michigan Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		140.9	129.4
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(119.4)	(162.2)
Ohio Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		259.6	253.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(30.7)	(25.5)
Public Service Co Of Oklahoma [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		6.4	3.3
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(13.7)	(13.6)
Southwestern Electric Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		75.8	78.7
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		$ (49.3)	$ (47.3)
Pension Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.80%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.80%	4.85%	4.95%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 5,224.9	$ 4,841.7
Service Cost		93.5	71.9	$ 69.2
Interest Cost		205.3	221	202.8
Actuarial (Gain) Loss		(200.6)	387
Benefit Payments		(330.2)	(296.7)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		4,992.9	5,224.9	4,841.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		4,967.5	4,711.2
Actual Gain (Loss) on Plan Assets		32.4	474.2
Company Contributions		97.9	78.8
Participant Contributions		0	0
Benefit Payments		(330.2)	(296.7)
Fair Value of Plan Assets as of December 31		4,767.6	4,967.5	$ 4,711.2
Funded (Underfunded) Status as of December 31		(225.3)	(257.4)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(6.3)	(6.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(219)	(251.2)
Funded (Underfunded) Status		(225.3)	(257.4)
Components
Net Actuarial Loss		1,546.1	1,611.4
Prior Service Cost (Credit)		3.3	5.5
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		41.8	174.4
Amortization of Actuarial Gain (Loss)		(107.1)	(124)
Amortization of Prior Service Credit (Cost)		(2.2)	(2.5)
Change for the Year		$ (67.5)	$ 47.9
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.80%	4.80%
Pension Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.45%	4.45%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.45%	4.60%	4.70%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 702.8	$ 663.2
Service Cost		8.7	7	$ 6.2
Interest Cost		26.7	29.6	27.7
Actuarial (Gain) Loss		(41.4)	41.7
Benefit Payments		(43.4)	(38.7)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		653.4	702.8	663.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		642.3	628
Actual Gain (Loss) on Plan Assets		(5.7)	44
Company Contributions		10	9
Participant Contributions		0	0
Benefit Payments		(43.4)	(38.7)
Fair Value of Plan Assets as of December 31		603.2	642.3	$ 628
Funded (Underfunded) Status as of December 31		(50.2)	(60.5)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(50.2)	(60.5)
Funded (Underfunded) Status		(50.2)	(60.5)
Components
Net Actuarial Loss		220.8	235
Prior Service Cost (Credit)		0.3	0.5
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(0.3)	31.6
Amortization of Actuarial Gain (Loss)		(13.9)	(16.6)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.2)
Change for the Year		$ (14.4)	$ 14.8
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.45%	4.45%
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.75%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.80%	4.90%	5.00%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 617.9	$ 574.7
Service Cost		12.9	10	$ 8.7
Interest Cost		24.5	26.3	24.1
Actuarial (Gain) Loss		(28.4)	38.5
Benefit Payments		(35.4)	(31.6)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		591.5	617.9	574.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		591.7	559.1
Actual Gain (Loss) on Plan Assets		(0.9)	55.3
Company Contributions		14.6	8.9
Participant Contributions		0	0
Benefit Payments		(35.4)	(31.6)
Fair Value of Plan Assets as of December 31		570	591.7	$ 559.1
Funded (Underfunded) Status as of December 31		(21.5)	(26.2)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(21.5)	(26.2)
Funded (Underfunded) Status		(21.5)	(26.2)
Components
Net Actuarial Loss		130	137.9
Prior Service Cost (Credit)		0.3	0.5
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		4.7	14.2
Amortization of Actuarial Gain (Loss)		(12.6)	(14.6)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.2)
Change for the Year		$ (8.1)	$ (0.6)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.75%	4.80%
Pension Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.85%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.80%	5.00%	5.00%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 526.3	$ 523.6
Service Cost		6.7	5.2	$ 5.3
Interest Cost		20.3	22.1	21.9
Actuarial (Gain) Loss		(19.5)	6.8
Benefit Payments		(36.3)	(31.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		497.5	526.3	523.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		498.5	501.6
Actual Gain (Loss) on Plan Assets		2.2	21.7
Company Contributions		7.7	6.6
Participant Contributions		0	0
Benefit Payments		(36.3)	(31.4)
Fair Value of Plan Assets as of December 31		472.1	498.5	$ 501.6
Funded (Underfunded) Status as of December 31		(25.4)	(27.8)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(25.4)	(27.8)
Funded (Underfunded) Status		(25.4)	(27.8)
Components
Net Actuarial Loss		222	226.7
Prior Service Cost (Credit)		0.2	0.4
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		5.8	11.5
Amortization of Actuarial Gain (Loss)		(10.5)	(12.4)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.2)
Change for the Year		$ (4.9)	$ (1.1)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.80%
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.85%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.80%	4.90%	4.90%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 285.4	$ 260.7
Service Cost		6.4	5.2	$ 5.6
Interest Cost		10.9	12.1	11
Actuarial (Gain) Loss		(17.9)	25.7
Benefit Payments		(19.4)	(18.3)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		265.4	285.4	260.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		275.5	264.6
Actual Gain (Loss) on Plan Assets		0.1	24.6
Company Contributions		5.9	4.6
Participant Contributions		0	0
Benefit Payments		(19.4)	(18.3)
Fair Value of Plan Assets as of December 31		262.1	275.5	$ 264.6
Funded (Underfunded) Status as of December 31		(3.3)	(9.9)
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.2)	(0.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(3.1)	(9.7)
Funded (Underfunded) Status		(3.3)	(9.9)
Components
Net Actuarial Loss		94.1	102.7
Prior Service Cost (Credit)		0.3	0.5
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(2.9)	15.7
Amortization of Actuarial Gain (Loss)		(5.7)	(6.7)
Amortization of Prior Service Credit (Cost)		(0.2)	(0.3)
Change for the Year		$ (8.8)	$ 8.7
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.80%
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Rate of Compensation Increase	[1]	4.80%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.00%	6.00%	6.50%
Rate of Compensation Increase	[2]	4.80%	4.85%	4.75%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 298.2	$ 270.6
Service Cost		8.3	6.6	$ 7
Interest Cost		11.8	12.7	11.5
Actuarial (Gain) Loss		(16.2)	27.5
Benefit Payments		(19.3)	(19.2)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		282.8	298.2	270.6
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		290.2	279
Actual Gain (Loss) on Plan Assets		1.6	26.5
Company Contributions		8.1	3.9
Participant Contributions		0	0
Benefit Payments		(19.3)	(19.2)
Fair Value of Plan Assets as of December 31		280.6	290.2	$ 279
Funded (Underfunded) Status as of December 31		(2.2)	(8)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.1)	(0.1)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(2.1)	(7.9)
Funded (Underfunded) Status		(2.2)	(8)
Components
Net Actuarial Loss		97.1	104.9
Prior Service Cost (Credit)		0.4	0.7
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		(1.8)	16.5
Amortization of Actuarial Gain (Loss)		(6)	(7.1)
Amortization of Prior Service Credit (Cost)		(0.3)	(0.3)
Change for the Year		$ (8.1)	$ 9.1
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.80%	4.80%
Pension Plans [Member] | Minimum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Maximum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Other Postretirement Benefit Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 3.7
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(3)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		70.5
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(57.4)
Change in Benefit Obligation
Benefit Obligation as of January 1		1,439	$ 1,455.5
Service Cost		12.2	14.2	$ 22.9
Interest Cost		56.8	67.2	70.8
Actuarial (Gain) Loss		37.2	(14.4)
Benefit Payments		(128.7)	(133.7)
Participant Contributions		33.3	41.9
Medicare Subsidy		0.8	8.3
Benefit Obligation as of December 31		1,450.6	1,439	1,455.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		1,693.9	1,698.7
Actual Gain (Loss) on Plan Assets		(34)	82.7
Company Contributions		12.9	4.3
Participant Contributions		33.3	41.9
Benefit Payments		(128.7)	(133.7)
Fair Value of Plan Assets as of December 31		1,577.4	1,693.9	$ 1,698.7
Funded (Underfunded) Status as of December 31		126.8	254.9
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		185.8	336.7
Other Current Liabilities - Accrued Short-term Benefit Liability		(3.3)	(3.6)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(55.7)	(78.2)
Funded (Underfunded) Status		126.8	254.9
Components
Net Actuarial Loss		577.4	419.9
Prior Service Cost (Credit)		(554.4)	(623.5)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		176.3	14
Amortization of Actuarial Gain (Loss)		(18.8)	(22.1)
Amortization of Prior Service Credit (Cost)		69.1	69
Change for the Year		$ 226.6	$ 60.9
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.8
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.6)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		15.2
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(12.3)
Change in Benefit Obligation
Benefit Obligation as of January 1		267.1	$ 279.9
Service Cost		1.1	1.4	$ 2.6
Interest Cost		10.3	12.8	13.5
Actuarial (Gain) Loss		2.5	(9)
Benefit Payments		(24.7)	(26.6)
Participant Contributions		5.7	7.2
Medicare Subsidy		0.2	1.4
Benefit Obligation as of December 31		262.2	267.1	279.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		280.6	284.8
Actual Gain (Loss) on Plan Assets		(7.7)	11.8
Company Contributions		2.8	3.4
Participant Contributions		5.7	7.2
Benefit Payments		(24.7)	(26.6)
Fair Value of Plan Assets as of December 31		256.7	280.6	$ 284.8
Funded (Underfunded) Status as of December 31		(5.5)	13.5
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		30.8	56.5
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.6)	(2.9)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(33.7)	(40.1)
Funded (Underfunded) Status		(5.5)	13.5
Components
Net Actuarial Loss		86.9	65.8
Prior Service Cost (Credit)		(80.6)	(90.6)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		24.7	(2.3)
Amortization of Actuarial Gain (Loss)		(3.6)	(4.6)
Amortization of Prior Service Credit (Cost)		10	10.1
Change for the Year		$ 31.1	$ 3.2
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.3
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.3)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		6.8
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(5.6)
Change in Benefit Obligation
Benefit Obligation as of January 1		161.7	$ 166.5
Service Cost		1.6	1.9	$ 3.2
Interest Cost		6.4	7.6	8.2
Actuarial (Gain) Loss		7.7	(4.9)
Benefit Payments		(15.2)	(15.7)
Participant Contributions		4	5.2
Medicare Subsidy		0.1	1.1
Benefit Obligation as of December 31		166.3	161.7	166.5
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		202.4	206.2
Actual Gain (Loss) on Plan Assets		(2.3)	6.6
Company Contributions		0.1	0.1
Participant Contributions		4	5.2
Benefit Payments		(15.2)	(15.7)
Fair Value of Plan Assets as of December 31		189	202.4	$ 206.2
Funded (Underfunded) Status as of December 31		22.7	40.7
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		22.7	40.7
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		22.7	40.7
Components
Net Actuarial Loss		77.1	54.4
Prior Service Cost (Credit)		(75.7)	(85.1)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		24.7	1.9
Amortization of Actuarial Gain (Loss)		(2)	(2.4)
Amortization of Prior Service Credit (Cost)		9.4	9.4
Change for the Year		$ 32.1	$ 8.9
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.3
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		6.9
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(5.7)
Change in Benefit Obligation
Benefit Obligation as of January 1		164.7	$ 171.2
Service Cost		0.9	1	$ 2.9
Interest Cost		6.4	7.6	9.5
Actuarial (Gain) Loss		8.7	(4.3)
Benefit Payments		(16.3)	(17.4)
Participant Contributions		4.3	5.6
Medicare Subsidy		(0.1)	1
Benefit Obligation as of December 31		168.6	164.7	171.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		206.2	212
Actual Gain (Loss) on Plan Assets		(2.6)	6
Company Contributions		0	0
Participant Contributions		4.3	5.6
Benefit Payments		(16.3)	(17.4)
Fair Value of Plan Assets as of December 31		191.6	206.2	$ 212
Funded (Underfunded) Status as of December 31		23	41.5
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		23	41.5
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		23	41.5
Components
Net Actuarial Loss		52.6	30.7
Prior Service Cost (Credit)		(55.4)	(62.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		24	3.3
Amortization of Actuarial Gain (Loss)		(2.1)	(2.4)
Amortization of Prior Service Credit (Cost)		7	6.9
Change for the Year		$ 28.9	$ 7.8
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		3.2
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(2.6)
Change in Benefit Obligation
Benefit Obligation as of January 1		76.7	$ 77.8
Service Cost		0.7	0.8	$ 1.4
Interest Cost		3	3.6	3.8
Actuarial (Gain) Loss		2.4	(1)
Benefit Payments		(7.1)	(7.3)
Participant Contributions		1.9	2.3
Medicare Subsidy		0.1	0.5
Benefit Obligation as of December 31		77.7	76.7	77.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		96	96.3
Actual Gain (Loss) on Plan Assets		(2.5)	4.7
Company Contributions		0	0
Participant Contributions		1.9	2.3
Benefit Payments		(7.1)	(7.3)
Fair Value of Plan Assets as of December 31		88.3	96	$ 96.3
Funded (Underfunded) Status as of December 31		10.6	19.3
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		10.6	19.3
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		10.6	19.3
Components
Net Actuarial Loss		35.2	25.3
Prior Service Cost (Credit)		(34.5)	(38.8)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		10.9	0.6
Amortization of Actuarial Gain (Loss)		(1)	(1.1)
Amortization of Prior Service Credit (Cost)		4.3	4.3
Change for the Year		$ 14.2	$ 3.8
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.30%	4.00%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.00%	4.70%	3.95%
Expected Return on Plan Assets		6.75%	6.75%	7.00%
Health Care Trend Rates
Initial		6.25%	6.50%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,020	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.2
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		3.5
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(2.9)
Change in Benefit Obligation
Benefit Obligation as of January 1		85	$ 87
Service Cost		0.8	1	$ 1.7
Interest Cost		3.4	4	4.3
Actuarial (Gain) Loss		2.1	(2.3)
Benefit Payments		(7.4)	(7.7)
Participant Contributions		2.1	2.5
Medicare Subsidy		0.1	0.5
Benefit Obligation as of December 31		86.1	85	87
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		106.4	107.7
Actual Gain (Loss) on Plan Assets		(3.3)	3.9
Company Contributions		0	0
Participant Contributions		2.1	2.5
Benefit Payments		(7.4)	(7.7)
Fair Value of Plan Assets as of December 31		97.8	106.4	$ 107.7
Funded (Underfunded) Status as of December 31		11.7	21.4
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		11.7	21.4
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		11.7	21.4
Components
Net Actuarial Loss		43.3	32.4
Prior Service Cost (Credit)		(41.6)	(46.8)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		12	0.8
Amortization of Actuarial Gain (Loss)		(1.1)	(1.2)
Amortization of Prior Service Credit (Cost)		5.2	5.2
Change for the Year		16.1	4.8
Regulatory Assets [Member] | Pension Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1,385.2	1,418.3
Regulatory Assets [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		218.3	232.8
Regulatory Assets [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		125.3	134.1
Regulatory Assets [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		222.2	227.1
Regulatory Assets [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		94.4	103.2
Regulatory Assets [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		97.5	105.6
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		15.1	(148.5)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		(0.7)	(20.3)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.1	(26.3)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		(2.8)	(31.7)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0.7	(13.5)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.2	(8.9)
Deferred Income Taxes [Member] | Pension Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		57.5	69.5
Deferred Income Taxes [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1	0.9
Deferred Income Taxes [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.8	1.5
Deferred Income Taxes [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		2.8	(19.3)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		2.4	(1.6)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0.1	(1.5)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0.2	(1.9)
Net of Tax AOCI [Member] | Pension Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		106.7	129.1
Net of Tax AOCI [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.8	1.8
Net of Tax AOCI [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		3.2	2.8
Net of Tax AOCI [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		5.1	(35.8)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		4.6	(2.9)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0.2	(2.9)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 0.3	$ (3.6)
[1]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
[2]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

Benefit Plans 2 (Details)

Benefit Plans 2 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	$ 28.7		$ (7.6)	$ 19
Transfers out of Level 3	[2],[3]	18.9		21.5	3.6
Appalachian Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0	[4]	(3.6)	1.3
Transfers out of Level 3	[2],[3]	(1.2)	[4]	0	0.9
Indiana Michigan Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0	[4]	(2.5)	0.9
Transfers out of Level 3	[2],[3]	(0.8)	[4]	0	0.6
Ohio Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0	1.9
Transfers out of Level 3	[2],[3]	0		0	1.3
Public Service Co Of Oklahoma [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0	0
Transfers out of Level 3	[2],[3]	0		0	0
Southwestern Electric Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0	0
Transfers out of Level 3	[2],[3]	0		0	0
Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4,767.6		$ 4,967.5	4,711.2
Year End Allocation
Total		100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 4,767.6		$ 4,967.5	4,711.2
Actual Return on Plan Assets
Balance as of December 31		$ 4,767.6		$ 4,967.5	4,711.2
Pension Plan [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments		12.70%		12.90%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 603.2		$ 642.3	628
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		603.2		642.3	628
Actual Return on Plan Assets
Balance as of December 31		$ 603.2		$ 642.3	628
Pension Plan [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.00%		11.90%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 570		$ 591.7	559.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		570		591.7	559.1
Actual Return on Plan Assets
Balance as of December 31		$ 570		$ 591.7	559.1
Pension Plan [Member] | Ohio Power Co [Member]
Allocated Assets of Investments		9.90%		10.00%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 472.1		$ 498.5	501.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		472.1		498.5	501.6
Actual Return on Plan Assets
Balance as of December 31		$ 472.1		$ 498.5	501.6
Pension Plan [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.50%		5.50%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 262.1		$ 275.5	264.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		262.1		275.5	264.6
Actual Return on Plan Assets
Balance as of December 31		$ 262.1		$ 275.5	264.6
Pension Plan [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments		5.90%		5.80%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 280.6		$ 290.2	279
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		280.6		290.2	279
Actual Return on Plan Assets
Balance as of December 31		280.6		290.2	279
Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,577.4		$ 1,693.9	1,698.7
Year End Allocation
Total		100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 1,577.4		$ 1,693.9	1,698.7
Actual Return on Plan Assets
Balance as of December 31		$ 1,577.4		$ 1,693.9	1,698.7
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments		16.30%		16.60%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 256.7		$ 280.6	284.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		256.7		280.6	284.8
Actual Return on Plan Assets
Balance as of December 31		$ 256.7		$ 280.6	284.8
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.00%		11.90%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 189		$ 202.4	206.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		189		202.4	206.2
Actual Return on Plan Assets
Balance as of December 31		$ 189		$ 202.4	206.2
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Allocated Assets of Investments		12.10%		12.20%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 191.6		$ 206.2	212
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		191.6		206.2	212
Actual Return on Plan Assets
Balance as of December 31		$ 191.6		$ 206.2	212
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.60%		5.70%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 88.3		$ 96	96.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		88.3		96	96.3
Actual Return on Plan Assets
Balance as of December 31		$ 88.3		$ 96	96.3
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments		6.20%		6.30%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 97.8		$ 106.4	107.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		97.8		106.4	107.7
Actual Return on Plan Assets
Balance as of December 31		97.8		106.4	107.7
Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		722		1,145.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		722		1,145.1
Actual Return on Plan Assets
Balance as of December 31		722		1,145.1
Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		994.3		1,079.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		994.3		1,079.5
Actual Return on Plan Assets
Balance as of December 31		994.3		1,079.5
Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3,609.9		3,406.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		3,609.9		3,406.7
Actual Return on Plan Assets
Balance as of December 31		3,609.9		3,406.7
Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		577.3		610.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		577.3		610.4
Actual Return on Plan Assets
Balance as of December 31		577.3		610.4
Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		674.5		627.3	567.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		674.5		627.3	567.9
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		(17)		37.2
Relating to Assets Sold During the Period		61.7		34.9
Purchases and Sales		2.5		(12.7)
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		674.5		627.3	567.9
Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		(238.8)		(211.6)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		(238.8)		(211.6)
Actual Return on Plan Assets
Balance as of December 31		(238.8)		(211.6)
Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		5.8		4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		5.8		4
Actual Return on Plan Assets
Balance as of December 31		5.8		4
Equity Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,123.4		$ 1,554.7
Year End Allocation
Total		23.50%		31.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 1,123.4		$ 1,554.7
Actual Return on Plan Assets
Balance as of December 31		1,123.4		1,554.7
Equity Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 996.6		$ 1,078.7
Year End Allocation
Total		63.20%		63.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 996.6		$ 1,078.7
Actual Return on Plan Assets
Balance as of December 31		996.6		1,078.7
Equity Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		722		1,145.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		722		1,145.1
Actual Return on Plan Assets
Balance as of December 31		722		1,145.1
Equity Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		949.4		1,032.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		949.4		1,032.7
Actual Return on Plan Assets
Balance as of December 31		949.4		1,032.7
Equity Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		401.4		409.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		401.4		409.6
Actual Return on Plan Assets
Balance as of December 31		401.4		409.6
Equity Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		47.2		46
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		47.2		46
Actual Return on Plan Assets
Balance as of December 31		47.2		46
Equity Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Equity Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Equity Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Equity Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 315.7		$ 588.6
Year End Allocation
Total		6.60%		11.90%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 315.7		$ 588.6
Actual Return on Plan Assets
Balance as of December 31		315.7		588.6
Domestic [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 465.1		$ 466.1
Year End Allocation
Total		29.50%		27.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 465.1		$ 466.1
Actual Return on Plan Assets
Balance as of December 31		465.1		466.1
Domestic [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		315.7		588.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		315.7		588.6
Actual Return on Plan Assets
Balance as of December 31		315.7		588.6
Domestic [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		465.1		466.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		465.1		466.1
Actual Return on Plan Assets
Balance as of December 31		465.1		466.1
Domestic [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 402.3		$ 502.2
Year End Allocation
Total		8.40%		10.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 402.3		$ 502.2
Actual Return on Plan Assets
Balance as of December 31		402.3		502.2
International [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 484.3		$ 566.6
Year End Allocation
Total		30.70%		33.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 484.3		$ 566.6
Actual Return on Plan Assets
Balance as of December 31		484.3		566.6
International [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		402.3		502.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		402.3		502.2
Actual Return on Plan Assets
Balance as of December 31		402.3		502.2
International [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		484.3		566.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		484.3		566.6
Actual Return on Plan Assets
Balance as of December 31		484.3		566.6
International [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 15.6		$ 14.1
Year End Allocation
Total		0.30%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 15.6		$ 14.1
Actual Return on Plan Assets
Balance as of December 31		15.6		14.1
Options [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 15.6		$ 16.4
Year End Allocation
Total		1.00%		1.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 15.6		$ 16.4
Actual Return on Plan Assets
Balance as of December 31		15.6		16.4
Options [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		15.6		14.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		15.6		14.1
Actual Return on Plan Assets
Balance as of December 31		15.6		14.1
Options [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		15.6		16.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		15.6		16.4
Actual Return on Plan Assets
Balance as of December 31		15.6		16.4
Options [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4		$ 54.3
Year End Allocation
Total		0.10%		1.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 4		$ 54.3
Actual Return on Plan Assets
Balance as of December 31		4		54.3
Real Estate Investment Trusts [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		4		54.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		4		54.3
Actual Return on Plan Assets
Balance as of December 31		4		54.3
Real Estate Investment Trusts [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 369.7		$ 377
Year End Allocation
Total		7.80%		7.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 369.7		$ 377
Actual Return on Plan Assets
Balance as of December 31		369.7		377
Common Collective Trust Global [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 19		$ 29.6
Year End Allocation
Total		1.20%		1.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 19		$ 29.6
Actual Return on Plan Assets
Balance as of December 31		19		29.6
Common Collective Trust Global [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		369.7		377
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		369.7		377
Actual Return on Plan Assets
Balance as of December 31		369.7		377
Common Collective Trust Global [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		19		29.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		19		29.6
Actual Return on Plan Assets
Balance as of December 31		19		29.6
Common Collective Trust Global [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust Global [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust International [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 16.1		$ 18.5
Year End Allocation
Total		0.30%		0.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 16.1		$ 18.5
Actual Return on Plan Assets
Balance as of December 31		16.1		18.5
Common Collective Trust International [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 12.6
Year End Allocation
Total		0.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 12.6
Actual Return on Plan Assets
Balance as of December 31		12.6
Common Collective Trust International [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust International [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0
Actual Return on Plan Assets
Balance as of December 31		0
Common Collective Trust International [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		16.1		18.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		16.1		18.5
Actual Return on Plan Assets
Balance as of December 31		16.1		18.5
Common Collective Trust International [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		12.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		12.6
Actual Return on Plan Assets
Balance as of December 31		12.6
Common Collective Trust International [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust International [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0
Actual Return on Plan Assets
Balance as of December 31		0
Common Collective Trust International [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust International [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0
Actual Return on Plan Assets
Balance as of December 31		0
Fixed Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 2,897		$ 2,724.1
Year End Allocation
Total		60.80%		54.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 2,897		$ 2,724.1
Actual Return on Plan Assets
Balance as of December 31		2,897		2,724.1
Fixed Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 310.3		$ 332.4
Year End Allocation
Total		19.60%		19.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 310.3		$ 332.4
Actual Return on Plan Assets
Balance as of December 31		310.3		332.4
Fixed Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,896.9		2,724
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		2,896.9		2,724
Actual Return on Plan Assets
Balance as of December 31		2,896.9		2,724
Fixed Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		310.3		332.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		310.3		332.4
Actual Return on Plan Assets
Balance as of December 31		310.3		332.4
Fixed Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0.1		0.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0.1		0.1
Actual Return on Plan Assets
Balance as of December 31		0.1		0.1
Fixed Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 34.2		$ 30.2
Year End Allocation
Total		0.70%		0.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 34.2		$ 30.2
Actual Return on Plan Assets
Balance as of December 31		34.2		30.2
Common Collective Trust - Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 100.9		$ 103.7
Year End Allocation
Total		6.40%		6.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 100.9		$ 103.7
Actual Return on Plan Assets
Balance as of December 31		100.9		103.7
Common Collective Trust - Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		34.2		30.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		34.2		30.2
Actual Return on Plan Assets
Balance as of December 31		34.2		30.2
Common Collective Trust - Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		100.9		103.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		100.9		103.7
Actual Return on Plan Assets
Balance as of December 31		100.9		103.7
Common Collective Trust - Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 421.9		$ 449.8
Year End Allocation
Total		8.90%		9.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 421.9		$ 449.8
Actual Return on Plan Assets
Balance as of December 31		421.9		449.8
United States Government and Agency Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 58.4		$ 71.1
Year End Allocation
Total		3.70%		4.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 58.4		$ 71.1
Actual Return on Plan Assets
Balance as of December 31		58.4		71.1
United States Government and Agency Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		421.9		449.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		421.9		449.8
Actual Return on Plan Assets
Balance as of December 31		421.9		449.8
United States Government and Agency Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		58.4		71.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		58.4		71.1
Actual Return on Plan Assets
Balance as of December 31		58.4		71.1
United States Government and Agency Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,983.2		$ 1,799.5
Year End Allocation
Total		41.60%		36.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 1,983.2		$ 1,799.5
Actual Return on Plan Assets
Balance as of December 31		1,983.2		1,799.5
Corporate Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 117.7		$ 125.5
Year End Allocation
Total		7.40%		7.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 117.7		$ 125.5
Actual Return on Plan Assets
Balance as of December 31		117.7		125.5
Corporate Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		1,983.2		1,799.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		1,983.2		1,799.5
Actual Return on Plan Assets
Balance as of December 31		1,983.2		1,799.5
Corporate Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		117.7		125.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		117.7		125.5
Actual Return on Plan Assets
Balance as of December 31		117.7		125.5
Corporate Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 421.5		$ 400.6
Year End Allocation
Total		8.80%		8.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 421.5		$ 400.6
Actual Return on Plan Assets
Balance as of December 31		421.5		400.6
Foreign Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 20.7		$ 21.3
Year End Allocation
Total		1.30%		1.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 20.7		$ 21.3
Actual Return on Plan Assets
Balance as of December 31		20.7		21.3
Foreign Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		421.4		400.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		421.4		400.5
Actual Return on Plan Assets
Balance as of December 31		421.4		400.5
Foreign Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20.7		21.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		20.7		21.3
Actual Return on Plan Assets
Balance as of December 31		20.7		21.3
Foreign Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0.1		0.1	0.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0.1		0.1	0.1
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		0
Relating to Assets Sold During the Period		0		0
Purchases and Sales		0		0
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		0.1		0.1	0.1
Foreign Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 12.8		$ 14.9
Year End Allocation
Total		0.30%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 12.8		$ 14.9
Actual Return on Plan Assets
Balance as of December 31		12.8		14.9
State and Local Government [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4.2		$ 5.9
Year End Allocation
Total		0.30%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 4.2		$ 5.9
Actual Return on Plan Assets
Balance as of December 31		4.2		5.9
State and Local Government [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		12.8		14.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		12.8		14.9
Actual Return on Plan Assets
Balance as of December 31		12.8		14.9
State and Local Government [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		4.2		5.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		4.2		5.9
Actual Return on Plan Assets
Balance as of December 31		4.2		5.9
State and Local Government [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 23.4		$ 29.1
Year End Allocation
Total		0.50%		0.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 23.4		$ 29.1
Actual Return on Plan Assets
Balance as of December 31		23.4		29.1
Other - Asset Backed [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 8.4		$ 4.9
Year End Allocation
Total		0.50%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 8.4		$ 4.9
Actual Return on Plan Assets
Balance as of December 31		8.4		4.9
Other - Asset Backed [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		23.4		29.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		23.4		29.1
Actual Return on Plan Assets
Balance as of December 31		23.4		29.1
Other - Asset Backed [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		8.4		4.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		8.4		4.9
Actual Return on Plan Assets
Balance as of December 31		8.4		4.9
Other - Asset Backed [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 42		$ 12.5
Year End Allocation
Total		0.90%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 42		$ 12.5
Actual Return on Plan Assets
Balance as of December 31		42		12.5
Infrastructure [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		42		12.5	0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		42		12.5	0
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		(3.6)		(0.3)
Relating to Assets Sold During the Period		0.3		0.1
Purchases and Sales		32.8		12.7
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		42		12.5	0
Infrastructure [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 253.7		$ 235.8
Year End Allocation
Total		5.30%		4.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 253.7		$ 235.8
Actual Return on Plan Assets
Balance as of December 31		253.7		235.8
Real Estate [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		253.7		235.8	238.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		253.7		235.8	238.2
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		12.5		5.5
Relating to Assets Sold During the Period		23.8		19
Purchases and Sales		(18.4)		(26.9)
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		253.7		235.8	238.2
Real Estate [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 378.7		$ 378.9
Year End Allocation
Total		8.00%		7.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 378.7		$ 378.9
Actual Return on Plan Assets
Balance as of December 31		378.7		378.9
Alternative Investments [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		378.7		378.9	329.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		378.7		378.9	329.6
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		(25.9)		32
Relating to Assets Sold During the Period		37.6		15.8
Purchases and Sales		(11.9)		1.5
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		378.7		378.9	$ 329.6
Alternative Investments [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 263		$ 219.8
Year End Allocation
Total		5.50%		4.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 263		$ 219.8
Actual Return on Plan Assets
Balance as of December 31		263		219.8
Securities Lending [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		263		219.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		263		219.8
Actual Return on Plan Assets
Balance as of December 31		263		219.8
Securities Lending [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending Collateral [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ (264.7)		$ (221.5)
Year End Allocation
Total	[5]	(5.50%)		(4.50%)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	$ (264.7)		$ (221.5)
Actual Return on Plan Assets
Balance as of December 31	[5]	(264.7)		(221.5)
Securities Lending Collateral [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Securities Lending Collateral [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Securities Lending Collateral [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Securities Lending Collateral [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	(264.7)		(221.5)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	(264.7)		(221.5)
Actual Return on Plan Assets
Balance as of December 31	[5]	(264.7)		(221.5)
Trusted Owned Life Insurance [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 212.6		$ 222.4
Year End Allocation
Total		13.50%		13.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 212.6		$ 222.4
Actual Return on Plan Assets
Balance as of December 31		212.6		222.4
Trusted Owned Life Insurance [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Trusted Owned Life Insurance [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		212.6		222.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		212.6		222.4
Actual Return on Plan Assets
Balance as of December 31		212.6		222.4
Trusted Owned Life Insurance [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Trusted Owned Life Insurance [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International Equities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 28.3		$ 10.3
Year End Allocation
Total		1.80%		0.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 28.3		$ 10.3
Actual Return on Plan Assets
Balance as of December 31		28.3		10.3
International Equities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International Equities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		28.3		10.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		28.3		10.3
Actual Return on Plan Assets
Balance as of December 31		28.3		10.3
International Equities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International Equities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Bonds [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 184.3		$ 212.1
Year End Allocation
Total		11.70%		12.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 184.3		$ 212.1
Actual Return on Plan Assets
Balance as of December 31		184.3		212.1
United States Bonds [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Bonds [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		184.3		212.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		184.3		212.1
Actual Return on Plan Assets
Balance as of December 31		184.3		212.1
United States Bonds [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Bonds [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 48.6		$ 53.3
Year End Allocation
Total		1.00%		1.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 48.6		$ 53.3
Actual Return on Plan Assets
Balance as of December 31		48.6		53.3
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 52.1		$ 56.4
Year End Allocation
Total		3.30%		3.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 52.1		$ 56.4
Actual Return on Plan Assets
Balance as of December 31		52.1		56.4
Cash and Cash Equivalents [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		44.9		46.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		44.9		46.8
Actual Return on Plan Assets
Balance as of December 31		44.9		46.8
Cash and Cash Equivalents [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		48.6		53.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		48.6		53.3
Actual Return on Plan Assets
Balance as of December 31		48.6		53.3
Cash and Cash Equivalents [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		7.2		9.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		7.2		9.6
Actual Return on Plan Assets
Balance as of December 31		7.2		9.6
Cash and Cash Equivalents [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Pending Transactions and Accrued Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	$ 25.9		$ 9.9
Year End Allocation
Total	[6]	0.50%		0.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	$ 25.9		$ 9.9
Actual Return on Plan Assets
Balance as of December 31	[6]	25.9		9.9
Other - Pending Transactions and Accrued Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	$ 5.8		$ 4
Year End Allocation
Total	[7]	0.40%		0.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	$ 5.8		$ 4
Actual Return on Plan Assets
Balance as of December 31	[7]	5.8		4
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	25.9		9.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	25.9		9.9
Actual Return on Plan Assets
Balance as of December 31	[6]	25.9		9.9
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	5.8		4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	5.8		4
Actual Return on Plan Assets
Balance as of December 31	[7]	$ 5.8		$ 4
[1]	Represents existing assets or liabilities that were previously categorized as Level 2.
[2]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[3]	Represents existing assets or liabilities that were previously categorized as Level 3.
[4]	Includes both affiliated and nonaffiliated transactions.
[5]	Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.
[6]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
[7]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Benefit Plans 3 (Details)

Benefit Plans 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 73.6	$ 70.5	$ 66.6
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Multiemployer Plan Surcharge	10.00%	5.00%
Multiemployer Plans Withdrawal Obligation	$ 31	$ 40
Noncurrent Regulatory Assets	5,140.3	4,263.7
UMWA Withdrawal Obligation [Member]
Benefit Plans Textuals [Abstract]
Noncurrent Regulatory Assets	14	25
Appalachian Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.2	$ 7.3	7.4
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Multiemployer Plan Surcharge	10.00%	5.00%
Noncurrent Regulatory Assets	$ 1,154.2	$ 857.9
Indiana Michigan Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 10.6	10.5	10
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 804.3	536.2
Ohio Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.4	5.2	6.5
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 1,113	1,318.9
Public Service Co Of Oklahoma [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 4.2	4	3.8
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 214.8	154.3
Southwestern Electric Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.7	5.3	5
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 415.8	393.6
Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,832.7	5,058
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	4,992.9	5,224.9	4,841.7
Accumulated Benefit Obligation	4,832.7	5,058
Fair Value of Plan Assets	4,767.6	4,967.5	4,711.2
Underfunded Status, Accumulated Benefit Obligation	(65.1)	(90.5)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	95.6
Components of Net Periodic Benefit Cost
Service Cost	93.5	71.9	69.2
Interest Cost	205.3	221	202.8
Expected Return on Plan Assets	(274.8)	(261.6)	(277.8)
Amortization of Prior Service Cost (Credit)	2.2	2.5	2.8
Amortization of Net Actuarial Loss	107.1	124	183.1
Net Periodic Benefit Cost (Credit)	133.3	157.8	180.1
Capitalized Portion	(48.4)	(52.2)	(56.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	84.9	105.6	123.7
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	82.9
Prior Service Cost (Credit)	2.2
Total Estimated 2016 Amortization	85.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	85.1
Pension Plans [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	324
2,017	335.5
2,018	339.3
2,019	348.7
2,020	355.9
Years 2021 to 2025, in Total	1,844.3
Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	641.9	689.1
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	653.4	702.8	663.2
Accumulated Benefit Obligation	641.9	689.1
Fair Value of Plan Assets	603.2	642.3	628
Underfunded Status, Accumulated Benefit Obligation	(38.7)	(46.8)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	10.7
Components of Net Periodic Benefit Cost
Service Cost	8.7	7	6.2
Interest Cost	26.7	29.6	27.7
Expected Return on Plan Assets	(35)	(33.9)	(37.1)
Amortization of Prior Service Cost (Credit)	0.2	0.2	0.2
Amortization of Net Actuarial Loss	13.9	16.6	25
Net Periodic Benefit Cost (Credit)	14.5	19.5	22
Capitalized Portion	(5.5)	(6.8)	(7.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	9	12.7	14.5
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	10.7
Prior Service Cost (Credit)	0.2
Total Estimated 2016 Amortization	10.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	10.9
Pension Plans [Member] | Appalachian Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	42.8
2,017	43.2
2,018	44.2
2,019	44.6
2,020	45
Years 2021 to 2025, in Total	232.3
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	571.7	598.7
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	591.5	617.9	574.7
Accumulated Benefit Obligation	571.7	598.7
Fair Value of Plan Assets	570	591.7	559.1
Underfunded Status, Accumulated Benefit Obligation	(1.7)	(7)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	13.1
Components of Net Periodic Benefit Cost
Service Cost	12.9	10	8.7
Interest Cost	24.5	26.3	24.1
Expected Return on Plan Assets	(32.6)	(31)	(32.8)
Amortization of Prior Service Cost (Credit)	0.2	0.2	0.2
Amortization of Net Actuarial Loss	12.6	14.6	21.7
Net Periodic Benefit Cost (Credit)	17.6	20.1	21.9
Capitalized Portion	(4)	(4.6)	(4.6)
Net Periodic Benefit Cost (Credit) Recognized in Expense	13.6	15.5	17.3
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	9.7
Prior Service Cost (Credit)	0.2
Total Estimated 2016 Amortization	9.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	9.9
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	33.9
2,017	35.6
2,018	36
2,019	38.6
2,020	39.3
Years 2021 to 2025, in Total	213.1
Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	484.2	512.5
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	497.5	526.3	523.6
Accumulated Benefit Obligation	484.2	512.5
Fair Value of Plan Assets	472.1	498.5	501.6
Underfunded Status, Accumulated Benefit Obligation	(12.1)	(14)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	7.5
Components of Net Periodic Benefit Cost
Service Cost	6.7	5.2	5.3
Interest Cost	20.3	22.1	21.9
Expected Return on Plan Assets	(27.5)	(26.5)	(29.9)
Amortization of Prior Service Cost (Credit)	0.2	0.2	0.2
Amortization of Net Actuarial Loss	10.5	12.4	19.8
Net Periodic Benefit Cost (Credit)	10.2	13.4	17.3
Capitalized Portion	(4.8)	(5.5)	(6.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense	5.4	7.9	11.1
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	8.2
Prior Service Cost (Credit)	0.1
Total Estimated 2016 Amortization	8.3
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	8.3
Pension Plans [Member] | Ohio Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	36.4
2,017	36
2,018	35.8
2,019	36.1
2,020	36.2
Years 2021 to 2025, in Total	174.3
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	254.4	272.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	265.4	285.4	260.7
Accumulated Benefit Obligation	254.4	272.8
Fair Value of Plan Assets	262.1	275.5	264.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	5.7
Components of Net Periodic Benefit Cost
Service Cost	6.4	5.2	5.6
Interest Cost	10.9	12.1	11
Expected Return on Plan Assets	(15.1)	(14.6)	(15.7)
Amortization of Prior Service Cost (Credit)	0.2	0.3	0.3
Amortization of Net Actuarial Loss	5.7	6.7	9.8
Net Periodic Benefit Cost (Credit)	8.1	9.7	11
Capitalized Portion	(2.8)	(3.3)	(3.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	5.3	6.4	7.6
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.4
Prior Service Cost (Credit)	0.2
Total Estimated 2016 Amortization	4.6
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	4.6
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	19.3
2,017	20.2
2,018	20.1
2,019	20.9
2,020	21.3
Years 2021 to 2025, in Total	109.1
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	269.3	283
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	282.8	298.2	270.6
Accumulated Benefit Obligation	269.3	283
Fair Value of Plan Assets	280.6	290.2	279
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	6.9
Components of Net Periodic Benefit Cost
Service Cost	8.3	6.6	7
Interest Cost	11.8	12.7	11.5
Expected Return on Plan Assets	(16)	(15.4)	(16.5)
Amortization of Prior Service Cost (Credit)	0.3	0.3	0.3
Amortization of Net Actuarial Loss	6	7.1	10.2
Net Periodic Benefit Cost (Credit)	10.4	11.3	12.5
Capitalized Portion	(3.2)	(3.4)	(3.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	7.2	7.9	9
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.7
Prior Service Cost (Credit)	0.3
Total Estimated 2016 Amortization	5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	5
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	18.6
2,017	20.2
2,018	21.1
2,019	21.8
2,020	22.4
Years 2021 to 2025, in Total	120.2
Other Postretirement Benefit Plans [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1,450.6	1,439	1,455.5
Fair Value of Plan Assets	1,577.4	1,693.9	1,698.7
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	6
Components of Net Periodic Benefit Cost
Service Cost	12.2	14.2	22.9
Interest Cost	56.8	67.2	70.8
Expected Return on Plan Assets	(111)	(111.3)	(106.6)
Amortization of Prior Service Cost (Credit)	(69.1)	(69)	(69)
Amortization of Net Actuarial Loss	18.8	22.1	64.7
Net Periodic Benefit Cost (Credit)	(92.3)	(76.8)	(17.2)
Capitalized Portion	33.5	25.3	5.4
Net Periodic Benefit Cost (Credit) Recognized in Expense	(58.8)	(51.5)	(11.8)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	29.8
Prior Service Cost (Credit)	(69)
Total Estimated 2016 Amortization	(39.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(39.2)
Other Postretirement Benefit Plans [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	134.1
2,017	136.7
2,018	139.1
2,019	140.3
2,020	143.6
Years 2021 to 2025, in Total	749.7
Other Postretirement Benefit Plans [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0.3
2,017	0.3
2,018	0.3
2,019	0.3
2,020	0.3
Years 2021 to 2025, in Total	1.8
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	262.2	267.1	279.9
Fair Value of Plan Assets	256.7	280.6	284.8
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	2.6
Components of Net Periodic Benefit Cost
Service Cost	1.1	1.4	2.6
Interest Cost	10.3	12.8	13.5
Expected Return on Plan Assets	(18.1)	(18.5)	(18.1)
Amortization of Prior Service Cost (Credit)	(10)	(10.1)	(10.1)
Amortization of Net Actuarial Loss	3.6	4.6	12.2
Net Periodic Benefit Cost (Credit)	(13.1)	(9.8)	0.1
Capitalized Portion	5	3.4	(0.1)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(8.1)	(6.4)	0
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	5.2
Prior Service Cost (Credit)	(10.1)
Total Estimated 2016 Amortization	(4.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(4.9)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	25.3
2,017	25.4
2,018	25.6
2,019	25.3
2,020	25.6
Years 2021 to 2025, in Total	127.9
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0.2
2,017	0.2
2,018	0.2
2,019	0.2
2,020	0.2
Years 2021 to 2025, in Total	1.1
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	166.3	161.7	166.5
Fair Value of Plan Assets	189	202.4	206.2
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	0
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.9	3.2
Interest Cost	6.4	7.6	8.2
Expected Return on Plan Assets	(13.2)	(13.4)	(13.2)
Amortization of Prior Service Cost (Credit)	(9.4)	(9.4)	(9.4)
Amortization of Net Actuarial Loss	2	2.4	7.5
Net Periodic Benefit Cost (Credit)	(12.6)	(10.9)	(3.7)
Capitalized Portion	2.9	2.5	0.8
Net Periodic Benefit Cost (Credit) Recognized in Expense	(9.7)	(8.4)	(2.9)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	3.5
Prior Service Cost (Credit)	(9.4)
Total Estimated 2016 Amortization	(5.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(5.9)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	15.9
2,017	16.2
2,018	16.6
2,019	16.8
2,020	17.2
Years 2021 to 2025, in Total	90.4
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Years 2021 to 2025, in Total	0
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	168.6	164.7	171.2
Fair Value of Plan Assets	191.6	206.2	212
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	0
Components of Net Periodic Benefit Cost
Service Cost	0.9	1	2.9
Interest Cost	6.4	7.6	9.5
Expected Return on Plan Assets	(13.4)	(13.5)	(13.5)
Amortization of Prior Service Cost (Credit)	(7)	(6.9)	(6.9)
Amortization of Net Actuarial Loss	2.1	2.4	8.6
Net Periodic Benefit Cost (Credit)	(11)	(9.4)	0.6
Capitalized Portion	5.2	3.8	(0.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense	(5.8)	(5.6)	0.4
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	3.6
Prior Service Cost (Credit)	(6.9)
Total Estimated 2016 Amortization	(3.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(3.3)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	16.9
2,017	17.1
2,018	17.3
2,019	17.3
2,020	17.5
Years 2021 to 2025, in Total	87.6
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Years 2021 to 2025, in Total	0
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	77.7	76.7	77.8
Fair Value of Plan Assets	88.3	96	96.3
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	0
Components of Net Periodic Benefit Cost
Service Cost	0.7	0.8	1.4
Interest Cost	3	3.6	3.8
Expected Return on Plan Assets	(6.3)	(6.3)	(6.1)
Amortization of Prior Service Cost (Credit)	(4.3)	(4.3)	(4.3)
Amortization of Net Actuarial Loss	1	1.1	3.5
Net Periodic Benefit Cost (Credit)	(5.9)	(5.1)	(1.7)
Capitalized Portion	2	1.7	0.5
Net Periodic Benefit Cost (Credit) Recognized in Expense	(3.9)	(3.4)	(1.2)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1.7
Prior Service Cost (Credit)	(4.3)
Total Estimated 2016 Amortization	(2.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(2.6)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	7.4
2,017	7.6
2,018	7.7
2,019	7.9
2,020	8.1
Years 2021 to 2025, in Total	42.7
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Years 2021 to 2025, in Total	0
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	86.1	85	87
Fair Value of Plan Assets	97.8	106.4	107.7
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2016	0
Components of Net Periodic Benefit Cost
Service Cost	0.8	1	1.7
Interest Cost	3.4	4	4.3
Expected Return on Plan Assets	(6.9)	(7)	(6.9)
Amortization of Prior Service Cost (Credit)	(5.2)	(5.2)	(5.1)
Amortization of Net Actuarial Loss	1.1	1.2	3.9
Net Periodic Benefit Cost (Credit)	(6.8)	(6)	(2.1)
Capitalized Portion	2.1	1.8	0.6
Net Periodic Benefit Cost (Credit) Recognized in Expense	(4.7)	(4.2)	$ (1.5)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1.8
Prior Service Cost (Credit)	(5.1)
Total Estimated 2016 Amortization	(3.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(3.3)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,016	7.9
2,017	8.1
2,018	8.3
2,019	8.4
2,020	8.7
Years 2021 to 2025, in Total	47.6
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Years 2021 to 2025, in Total	0
Qualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,757.1	4,982
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,757.1	4,982
Qualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	641.4	688.6
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	641.4	688.6
Qualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	571.3	598.2
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	571.3	598.2
Qualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	484.1	512.4
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	484.1	512.4
Qualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	252	270
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	252	270
Qualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	267.7	281.2
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	267.7	281.2
Nonqualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	75.6	76
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	75.6	76
Nonqualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.5	0.5
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.5	0.5
Nonqualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.4	0.5
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.4	0.5
Nonqualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.1	0.1
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.1	0.1
Nonqualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.4	2.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	2.6	2.8
Accumulated Benefit Obligation	2.4	2.8
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(2.4)	(2.8)
Nonqualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.6	1.8
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1.7	1.8
Accumulated Benefit Obligation	1.6	1.8
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(1.6)	$ (1.8)
Regulatory Assets [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	73.8
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	73.8
Regulatory Assets [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	10.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	10.9
Regulatory Assets [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	9.3
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	9.3
Regulatory Assets [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	8.3
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	8.3
Regulatory Assets [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	4.6
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	4.6
Regulatory Assets [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	5
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	5
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(28.5)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(28.5)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(2.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(2.6)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(5.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(5.3)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(3.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(3.3)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(2.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(2.6)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(2.1)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(2.1)
Deferred Income Taxes [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	3.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	3.9
Deferred Income Taxes [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0.2
Deferred Income Taxes [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(3.7)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(3.7)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(0.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(0.8)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(0.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(0.2)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(0.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(0.4)
Net of Tax AOCI [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	7.4
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	7.4
Net of Tax AOCI [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0.4
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0.4
Net of Tax AOCI [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(7)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(7)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(1.5)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(1.5)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(0.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	(0.4)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2016 Amortization	(0.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2016	$ (0.8)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended										12 Months Ended
		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Reportable Segment Information
Revenues		$ 3,614.7		$ 4,431.4	$ 3,826.7	$ 4,580.4	$ 3,819.1		$ 4,161.4	$ 3,900.6	$ 4,497.5	$ 16,453.2	$ 16,378.6		$ 14,813.5
Asset Impairments and Other Related Charges												0	0		226.4
Depreciation and Amortization												2,009.7	1,897.6		1,712.5
Interest and Investment Income												7.9	7.4		57.9
Carrying Costs Income												23.5	33.2		30.2
Interest Expense												873.9	868		890
Income Tax Expense (Credit)												919.6	902.6		677.7
Income from Continuing Operations		205.2		511.8	431.4	620.2	159.6		484.2	388.4	558.3	1,768.6	1,590.5		1,473.9
Income from Discontinued Operations, Net of Tax		265.5	[1]	7.8	(0.1)	10.5	31.9		10.2	2.7	2.7	283.7	47.5		10.3
NET INCOME (LOSS)		470.7		$ 519.6	$ 431.3	$ 630.7	191.5	[2]	$ 494.4	$ 391.1	$ 561	2,052.3	1,638		1,484.2
Gross Property Additions												4,513.3	4,194.8		3,648.4
Balance Sheet Information
Total Property, Plant and Equipment		65,481.4					63,605.9					65,481.4	63,605.9
Accumulated Depreciation and Amortization		19,348.2					19,970.8					19,348.2	19,970.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,133.2					43,635.1	[3]				46,133.2	43,635.1	[3]
Assets from Discontinued Operations							624.9						624.9
Total Assets		61,683.1					59,544.6					61,683.1	59,544.6		56,321
Investments in Equity Method Investees		720.5					648.4					720.5	648.4
Long-term Debt Due Within One Year - Affiliated		0					0					0	0
Long-term Debt Due Within One Year		1,831.8					2,500.4					1,831.8	2,500.4
Long-term Debt - Affiliated		0					0					0	0
Long-term Debt		17,740.9					16,012					17,740.9	16,012
Total Long-term Debt Outstanding		19,572.7					18,512.4	[4],[5]				19,572.7	18,512.4	[4],[5]
Liabilities from Discontinued Operations	[6]						434.8						434.8
Consolidation Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net												0	(51.2)	[7]	(79.5)	[7]
Revenues												(1,116.5)	(2,056.3)		(3,489.1)
Asset Impairments and Other Related Charges															0
Depreciation and Amortization	[8]											15.5	(43.7)		(66.8)
Interest and Investment Income												(15.3)	(19.4)		(21.8)
Carrying Costs Income												0.1	0		0
Interest Expense	[8]											(27.2)	(31.7)		(33.5)
Income Tax Expense (Credit)												0	0		0
Income from Continuing Operations												0	0		0
Income from Discontinued Operations, Net of Tax												0	0		0
NET INCOME (LOSS)												0	0		0
Gross Property Additions												(17.8)	(28)		(81.4)
Balance Sheet Information
Total Property, Plant and Equipment	[8]	(279.2)					(271.5)					(279.2)	(271.5)
Accumulated Depreciation and Amortization	[8]	(112.2)					(98.2)					(112.2)	(98.2)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[8]	(167)					(173.3)					(167)	(173.3)
Assets from Discontinued Operations							0						0
Total Assets	[8],[9]	(21,083.4)					(20,346.6)					(21,083.4)	(20,346.6)		(19,530.2)
Investments in Equity Method Investees		0					0					0	0
Long-term Debt Due Within One Year - Affiliated		0					(197)					0	(197)
Long-term Debt Due Within One Year		0					0					0	0
Long-term Debt - Affiliated		(52.2)					(52.2)					(52.2)	(52.2)
Long-term Debt		0					0					0	0
Total Long-term Debt Outstanding		(52.2)					(249.2)					(52.2)	(249.2)
Liabilities from Discontinued Operations							0						0
Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net												(1,116.5)	(2,005.1)		(3,409.6)
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net												9,069.9	9,396.8	[10]	9,346.6
Revenues												9,172.2	9,484.4		9,992.5
Asset Impairments and Other Related Charges															72.1
Depreciation and Amortization												1,062.6	1,033		941.5
Interest and Investment Income												4.6	3.4		7.2
Carrying Costs Income												11.8	6.7		13.8
Interest Expense												517.4	525.5		540.1
Income Tax Expense (Credit)												449.3	433.5		398.1
Income from Continuing Operations												900.2	711.8		681.7
Income from Discontinued Operations, Net of Tax												0	0		0
NET INCOME (LOSS)												900.2	711.8		681.7
Gross Property Additions												2,222.3	2,054.7		1,822
Balance Sheet Information
Total Property, Plant and Equipment		40,130.3					39,402.4					40,130.3	39,402.4
Accumulated Depreciation and Amortization		12,335					12,772.8					12,335	12,772.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		27,795.3					26,629.6					27,795.3	26,629.6
Assets from Discontinued Operations							0						0
Total Assets		35,792.3					33,705.1					35,792.3	33,705.1		32,745.5
Investments in Equity Method Investees		31.9					26.2					31.9	26.2
Long-term Debt Due Within One Year - Affiliated		0					111					0	111
Long-term Debt Due Within One Year		935.4					1,352.4					935.4	1,352.4
Long-term Debt - Affiliated		20					20					20	20
Long-term Debt		9,833					8,589.2					9,833	8,589.2
Total Long-term Debt Outstanding		10,788.4					10,072.6					10,788.4	10,072.6
Liabilities from Discontinued Operations							0						0
Vertically Integrated Utilities [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net												102.3	87.6	[10]	645.9
Transmission and Distribution Companies [Member]
Reportable Segment Information
Sales Revenue, Net												4,392	4,552.6		4,279.1
Revenues												4,556.6	4,813.6		4,478.4
Asset Impairments and Other Related Charges															0
Depreciation and Amortization												686.2	657.8		591.3
Interest and Investment Income												6.1	11.4		1.6
Carrying Costs Income												11.8	26.5		16.3
Interest Expense												275.8	279.9		291
Income Tax Expense (Credit)												185.5	211.1		198.3
Income from Continuing Operations												351.7	354.6		357.8
Income from Discontinued Operations, Net of Tax												0	0		0
NET INCOME (LOSS)												351.7	354.6		357.8
Gross Property Additions												1,048.3	1,037.7		870.9
Balance Sheet Information
Total Property, Plant and Equipment		13,840.5					13,023.8					13,840.5	13,023.8
Accumulated Depreciation and Amortization		3,529.2					3,480.7					3,529.2	3,480.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,311.3					9,543.1					10,311.3	9,543.1
Assets from Discontinued Operations							0						0
Total Assets		14,640.2					14,463.4					14,640.2	14,463.4		14,127.3
Investments in Equity Method Investees		0.9					1.1					0.9	1.1
Long-term Debt Due Within One Year - Affiliated		0					0					0	0
Long-term Debt Due Within One Year		824.7					405.2					824.7	405.2
Long-term Debt - Affiliated		0					0					0	0
Long-term Debt		4,776.8					5,224.2					4,776.8	5,224.2
Total Long-term Debt Outstanding		5,601.5					5,629.4					5,601.5	5,629.4
Liabilities from Discontinued Operations							0						0
Transmission and Distribution Companies [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net												164.6	261		199.3
AEP Transmission Holdco
Reportable Segment Information
Sales Revenue, Net												100.6	73.9		26.8
Revenues												329.2	191.9		77.7
Asset Impairments and Other Related Charges															0
Depreciation and Amortization												43	23.7		10.1
Interest and Investment Income												0.2	0		0
Carrying Costs Income												(0.2)	0		0.1
Interest Expense												37.2	23.5		10
Income Tax Expense (Credit)												91.3	62.9		29
Income from Continuing Operations												192.7	150.8		79.4
Income from Discontinued Operations, Net of Tax												0	0		0
NET INCOME (LOSS)												192.7	150.8		79.4
Gross Property Additions												1,121.3	948.3		842.6
Balance Sheet Information
Total Property, Plant and Equipment		3,977.6					2,714.2					3,977.6	2,714.2
Accumulated Depreciation and Amortization		52.3					24.5					52.3	24.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,925.3					2,689.7					3,925.3	2,689.7
Assets from Discontinued Operations							0						0
Total Assets		5,012.1					3,570					5,012.1	3,570		2,241.5
Investments in Equity Method Investees		630.8					548					630.8	548
Long-term Debt Due Within One Year - Affiliated		0					0					0	0
Long-term Debt Due Within One Year		0					0					0	0
Long-term Debt - Affiliated		0					0					0	0
Long-term Debt		1,648.4					1,147.5					1,648.4	1,147.5
Total Long-term Debt Outstanding		1,648.4					1,147.5					1,648.4	1,147.5
Liabilities from Discontinued Operations							0						0
AEP Transmission Holdco | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net												228.6	118		50.9
Generation and Marketing [Member]
Reportable Segment Information
Sales Revenue, Net												2,866.7	2,384.3	[10]	1,208
Revenues												3,412.7	3,849.6		3,665.2
Asset Impairments and Other Related Charges															154.3
Depreciation and Amortization												201.4	226.8		236.1
Interest and Investment Income												2.8	4.7		2.1
Carrying Costs Income												0	0		0
Interest Expense												40	45.3		55.5
Income Tax Expense (Credit)												194.6	179.3		112.2
Income from Continuing Operations												366	367.4		227.9
Income from Discontinued Operations, Net of Tax												0	0		0
NET INCOME (LOSS)												366	367.4		227.9
Gross Property Additions												134.3	164.9		185.2
Balance Sheet Information
Total Property, Plant and Equipment		7,461.3					8,394.3					7,461.3	8,394.3
Accumulated Depreciation and Amortization		3,367					3,602.9					3,367	3,602.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,094.3					4,791.4					4,094.3	4,791.4
Assets from Discontinued Operations							0						0
Total Assets		5,414.5					6,326.2					5,414.5	6,326.2		6,424
Investments in Equity Method Investees		0.1					0.1					0.1	0.1
Long-term Debt Due Within One Year - Affiliated		0					86					0	86
Long-term Debt Due Within One Year		71.6					740					71.6	740
Long-term Debt - Affiliated		32.2					32.2					32.2	32.2
Long-term Debt		639.5					214.8					639.5	214.8
Total Long-term Debt Outstanding		743.3					1,073					743.3	1,073
Liabilities from Discontinued Operations							0						0
Generation and Marketing [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net												546	1,465.3	[10]	2,457.2
All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[11]											24	22.2		32.5
Revenues	[11]											99	95.4		88.8
Asset Impairments and Other Related Charges	[11]														0
Depreciation and Amortization	[11]											1	0		0.3
Interest and Investment Income	[11]											9.5	7.3		68.8
Carrying Costs Income	[11]											0	0		0
Interest Expense	[11]											30.7	25.5		26.9
Income Tax Expense (Credit)	[11]											(1.1)	15.8		(59.9)
Income from Continuing Operations	[11]											(42)	5.9		127.1
Income from Discontinued Operations, Net of Tax	[11]											283.7	47.5		10.3
NET INCOME (LOSS)	[11]											241.7	53.4		137.4
Gross Property Additions	[11]											4.9	17.2		9.1
Balance Sheet Information
Total Property, Plant and Equipment	[11]	350.9					342.7					350.9	342.7
Accumulated Depreciation and Amortization	[11]	176.9					188.1					176.9	188.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[11]	174					154.6					174	154.6
Assets from Discontinued Operations	[11]						624.9						624.9
Total Assets	[11]	21,907.4					21,826.5					21,907.4	21,826.5		20,312.9
Investments in Equity Method Investees	[11]	56.8					73					56.8	73
Long-term Debt Due Within One Year - Affiliated	[11]	0					0					0	0
Long-term Debt Due Within One Year	[11]	0.1					2.8					0.1	2.8
Long-term Debt - Affiliated	[11]	0					0					0	0
Long-term Debt	[11]	843.2					836.3					843.2	836.3
Total Long-term Debt Outstanding	[11]	$ 843.3					839.1					843.3	839.1
Liabilities from Discontinued Operations	[11]						$ 434.8						434.8
All Other [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net	[11]											$ 75	$ 73.2		$ 56.3
[1]	Includes sale of AEPRO (see Note 7).
[2]	Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4).
[3]	Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[4]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
[5]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[6]	Amount includes debt related to AEPRO. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[7]	Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio.
[8]	Includes eliminations due to an intercompany capital lease.
[9]	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.
[10]	Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014.
[11]	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)MWhMMBTUTgal		Dec. 31, 2014USD ($)MWhMMBTUTgal		Dec. 31, 2013USD ($)
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 5.8		$ 3.5
Cash Collateral Paid Netted Against Risk Management Liabilities		44.4		35.2
Fair Value of Derivative Instruments
Current Risk Management Assets		134.4		177.9
Long-term Risk Management Assets		321.8		294.2
Total Assets		456.2		472.1
Current Risk Management Liabilities		87.1		91.6
Long-term Risk Management Liabilities		179.1		130.9
Total Liabilities		266.2		222.5
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		86.4		269.7		$ 56.9
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		3.2		3.8		(10.4)
Gain (Loss) on Fair Value Portion of Long-term Debt		$ (3.3)		(3.9)		10.4
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		144 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		17.5		36
Amount of Collateral Attributable to Other Contracts	[1]	297.8		280.6
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		300.1		235.2
Amount of Cash Collateral Posted		0.8		8.5
Additional Settlement Liability if Cross Default Provision is Triggered		240.6		178.2
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0		0.1
Cash Collateral Paid Netted Against Risk Management Liabilities		3.1		0.1
Fair Value of Derivative Instruments
Current Risk Management Assets		14.7		23.8
Long-term Risk Management Assets		0.1		4.9
Current Risk Management Liabilities		4.8		11
Long-term Risk Management Liabilities		0.1		2.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		$ 36.5		54.2		1.7
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		0 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		4.9		6.3
Amount of Collateral Attributable to Other Contracts		0.1		0.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		3.7		9
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		3.7		9
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0		0.2
Cash Collateral Paid Netted Against Risk Management Liabilities		0.6		0
Fair Value of Derivative Instruments
Current Risk Management Assets		10.6		22.3
Long-term Risk Management Assets		0		3.3
Current Risk Management Liabilities		6.3		5.2
Long-term Risk Management Liabilities		1.6		1.4
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		$ 15.9		49.2		1.5
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		0 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		3.3		4.3
Amount of Collateral Attributable to Other Contracts		0.1		0
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		2.5		6.1
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		2.5		6.1
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.5		0.1
Fair Value of Derivative Instruments
Current Risk Management Assets		0		7.2
Long-term Risk Management Assets		19.2		45.1
Current Risk Management Liabilities		3.6		1.9
Long-term Risk Management Liabilities		0		3
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		$ (30.1)		86		2
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		0 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		0		0
Amount of Collateral Attributable to Other Contracts		0		0
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		0		0
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		0
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.3		0.1
Fair Value of Derivative Instruments
Current Risk Management Assets		0.6		0
Current Risk Management Liabilities		0.2		0.9
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		$ 4.2		0.4		4.3
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		0 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		0		0.7
Amount of Collateral Attributable to Other Contracts		3.2		4.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		0		0
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		0
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.3		0.1
Fair Value of Derivative Instruments
Current Risk Management Assets		0.8		0
Current Risk Management Liabilities		3.1		1.1
Long-term Risk Management Liabilities		2.1		0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		$ 9.9		15.8		2.5
Impact of Cash Flow Hedges on the Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows		0 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		$ 0		0
Amount of Collateral the Registrants Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0		0
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		0		0.9
Amount of Collateral Attributable to Other Contracts		0.1		0.2
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		0		0
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		0
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[2]	438.5	[3]	452.7	[4]
Total Liabilities	[2]	236.6	[3]	198.4	[4]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	15.7		28.7
Total Liabilities	[2],[5]	4.9		13.1
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	12.3		25.6
Total Liabilities	[2],[5]	7.9		6.6
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	19.2		52.3
Total Liabilities	[2],[5]	3.6		4.9
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.6		0
Total Liabilities	[2],[5]	0.2		0.9
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.8		0
Total Liabilities	[2],[5]	5.2		1.1
Commodity [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	17.6		16.8
Hedging Liabilities	[6]	26.1		14.3
AOCI Gain (Loss) Net of Tax		(5.2)		1.6
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(0.4)		4.3
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50
Commodity [Member] | Appalachian Power Co [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		0		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0		0
Commodity [Member] | Indiana Michigan Power Co [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		0		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0		0
Commodity [Member] | Ohio Power Co [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		0		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0		0
Commodity [Member] | Public Service Co Of Oklahoma [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		0		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0		0
Commodity [Member] | Southwestern Electric Power Co [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		0		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0		0
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	368.8		392.6
Long-term Risk Management Assets	[7]	364.8		366.7
Total Assets	[7]	733.6		759.3
Current Risk Management Liabilities	[7]	347		328.6
Long-term Risk Management Liabilities	[7]	223.3		208
Total Liabilities	[7]	570.3		536.6
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	163.3		222.7
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	25.9		32.9
Long-term Risk Management Assets	[8]	0.3		5.2
Total Assets	[8]	26.2		38.1
Current Risk Management Liabilities	[8]	18.1		20.2
Long-term Risk Management Liabilities	[8]	0.3		2.3
Total Liabilities	[8]	18.4		22.5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	7.8		15.6
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	22.8		28.5
Long-term Risk Management Assets	[8]	0.6		3.5
Total Assets	[8]	23.4		32
Current Risk Management Liabilities	[8]	17		11.3
Long-term Risk Management Liabilities	[8]	2.6		1.6
Total Liabilities	[8]	19.6		12.9
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	3.8		19.1
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		7.2
Long-term Risk Management Assets	[8]	19.2		45.1
Total Assets	[8]	19.2		52.3
Current Risk Management Liabilities	[8]	4.1		2
Long-term Risk Management Liabilities	[8]	0		3
Total Liabilities	[8]	4.1		5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	15.1		47.3
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.6		0.4
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0.6		0.4
Current Risk Management Liabilities	[8]	0.5		1.3
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0.5		1.3
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0.1		(0.9)
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.8		0.5
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0.8		0.5
Current Risk Management Liabilities	[8]	3.4		1.6
Long-term Risk Management Liabilities	[8]	2.1		0
Total Liabilities	[8]	5.5		1.6
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(4.7)		(1.1)
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	8.2		30
Long-term Risk Management Assets	[7]	11.7		3.8
Total Assets	[7]	19.9		33.8
Current Risk Management Liabilities	[7]	9.1		23.4
Long-term Risk Management Liabilities	[7]	19.3		7.9
Total Liabilities	[7]	28.4		31.3
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(8.5)		2.5
Commodity [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Commodity [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Commodity [Member] | Hedging Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Commodity [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Commodity [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Interest Rate and Foreign Currency [Member]
Commodity
Derivative, Notional Amount		560.3		815.2
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0.4		1
AOCI Gain (Loss) Net of Tax		(17.2)		(19.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.5)		(2)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		3.6		3.9
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0.7		0.3
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		(13.3)		(14.4)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.3)		(1.1)
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		4.3		5.6
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		1.2		1.4
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		4.2		5
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		0.8		0.8
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0
AOCI Gain (Loss) Net of Tax		(9.1)		(11.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.7)		(2)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0.1		2.6
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0.1		2.6
Current Risk Management Liabilities	[7]	0.3		0.7
Long-term Risk Management Liabilities	[7]	3.2		9.2
Total Liabilities	[7]	3.5		9.9
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(3.4)		(7.3)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0		0
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0		0
Current Risk Management Liabilities	[8]	0		0
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0		0
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		377.1		425.2
Long-term Risk Management Assets		376.5		370.5
Total Assets		753.6		795.7
Current Risk Management Liabilities		356.4		352.7
Long-term Risk Management Liabilities		245.8		225.1
Total Liabilities		602.2		577.8
Total MTM Derivative Contract Net Assets (Liabilities)		151.4		217.9
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		25.9		32.9
Long-term Risk Management Assets		0.3		5.2
Total Assets		26.2		38.1
Current Risk Management Liabilities		18.1		20.2
Long-term Risk Management Liabilities		0.3		2.3
Total Liabilities		18.4		22.5
Total MTM Derivative Contract Net Assets (Liabilities)		7.8		15.6
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		22.8		28.5
Long-term Risk Management Assets		0.6		3.5
Total Assets		23.4		32
Current Risk Management Liabilities		17		11.3
Long-term Risk Management Liabilities		2.6		1.6
Total Liabilities		19.6		12.9
Total MTM Derivative Contract Net Assets (Liabilities)		3.8		19.1
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		0		7.2
Long-term Risk Management Assets		19.2		45.1
Total Assets		19.2		52.3
Current Risk Management Liabilities		4.1		2
Long-term Risk Management Liabilities		0		3
Total Liabilities		4.1		5
Total MTM Derivative Contract Net Assets (Liabilities)		15.1		47.3
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		0.6		0.4
Long-term Risk Management Assets		0		0
Total Assets		0.6		0.4
Current Risk Management Liabilities		0.5		1.3
Long-term Risk Management Liabilities		0		0
Total Liabilities		0.5		1.3
Total MTM Derivative Contract Net Assets (Liabilities)		0.1		(0.9)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		0.8		0.5
Long-term Risk Management Assets		0		0
Total Assets		0.8		0.5
Current Risk Management Liabilities		3.4		1.6
Long-term Risk Management Liabilities		2.1		0
Total Liabilities		5.5		1.6
Total MTM Derivative Contract Net Assets (Liabilities)		(4.7)		(1.1)
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(242.7)		(247.3)
Long-term Risk Management Assets	[9]	(54.7)		(76.3)
Total Assets	[9]	(297.4)		(323.6)
Current Risk Management Liabilities	[9]	(269.3)		(261.1)
Long-term Risk Management Liabilities	[9]	(66.7)		(94.2)
Total Liabilities	[9]	(336)		(355.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	38.6		31.7
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(10.3)		(9.1)
Long-term Risk Management Assets	[10]	(0.2)		(0.3)
Total Assets	[10]	(10.5)		(9.4)
Current Risk Management Liabilities	[10]	(13.3)		(9.2)
Long-term Risk Management Liabilities	[10]	(0.2)		(0.2)
Total Liabilities	[10]	(13.5)		(9.4)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	3		0
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(10.5)		(6.2)
Long-term Risk Management Assets	[10]	(0.6)		(0.2)
Total Assets	[10]	(11.1)		(6.4)
Current Risk Management Liabilities	[10]	(10.7)		(6.1)
Long-term Risk Management Liabilities	[10]	(1)		(0.2)
Total Liabilities	[10]	(11.7)		(6.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.6		(0.1)
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0		0
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	0		0
Current Risk Management Liabilities	[10]	(0.5)		(0.1)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	(0.5)		(0.1)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.5		0.1
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0		(0.4)
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	0		(0.4)
Current Risk Management Liabilities	[10]	(0.3)		(0.4)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	(0.3)		(0.4)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.3		0
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0		(0.5)
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	0		(0.5)
Current Risk Management Liabilities	[10]	(0.3)		(0.5)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	(0.3)		(0.5)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.3		0
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	134.4		177.9
Long-term Risk Management Assets	[11]	321.8		294.2
Total Assets	[11]	456.2		472.1
Current Risk Management Liabilities	[11]	87.1		91.6
Long-term Risk Management Liabilities	[11]	179.1		130.9
Total Liabilities	[11]	266.2		222.5
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	190		249.6
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	15.6		23.8
Long-term Risk Management Assets	[12]	0.1		4.9
Total Assets	[12]	15.7		28.7
Current Risk Management Liabilities	[12]	4.8		11
Long-term Risk Management Liabilities	[12]	0.1		2.1
Total Liabilities	[12]	4.9		13.1
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	10.8		15.6
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	12.3		22.3
Long-term Risk Management Assets	[12]	0		3.3
Total Assets	[12]	12.3		25.6
Current Risk Management Liabilities	[12]	6.3		5.2
Long-term Risk Management Liabilities	[12]	1.6		1.4
Total Liabilities	[12]	7.9		6.6
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	4.4		19
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	0		7.2
Long-term Risk Management Assets	[12]	19.2		45.1
Total Assets	[12]	19.2		52.3
Current Risk Management Liabilities	[12]	3.6		1.9
Long-term Risk Management Liabilities	[12]	0		3
Total Liabilities	[12]	3.6		4.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	15.6		47.4
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	0.6		0
Long-term Risk Management Assets	[12]	0		0
Total Assets	[12]	0.6		0
Current Risk Management Liabilities	[12]	0.2		0.9
Long-term Risk Management Liabilities	[12]	0		0
Total Liabilities	[12]	0.2		0.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	0.4		(0.9)
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	0.8		0
Long-term Risk Management Assets	[12]	0		0
Total Assets	[12]	0.8		0
Current Risk Management Liabilities	[12]	3.1		1.1
Long-term Risk Management Liabilities	[12]	2.1		0
Total Liabilities	[12]	5.2		1.1
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	$ (4.4)		$ (1.1)
Power [Member]
Commodity
Derivative, Energy Notional Amount | MWh		317.8		333.7
Power [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		40.9		32.5
Power [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		22.8		23.8
Power [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		13.3		20.3
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MWh		11.3		16.8
Power [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		14		20.5
Coal [Member]
Commodity
Derivative, Mass Notional Amount | T		4.4		3.1
Coal [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0.3
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		1.6		0.5
Coal [Member] | Ohio Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		2.8		1.5
Natural Gas [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		38.2		105.9
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0.3		0.4
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0.2		0.3
Natural Gas [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0.2		0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0.2		0
Heating Oil and Gasoline [Member]
Commodity
Derivative, Volume Notional Amount | gal		7.4		5.5
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.4		1.1
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.7		0.5
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.6		1.1
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.8		0.6
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.9		0.7
Interest Rate Contract [Member]
Commodity
Derivative, Notional Amount		$ 113.5		$ 152
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		2.4		5.1
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		1.6		3.5
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.7		35.4		15.1
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
Vertically Integrated Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Vertically Integrated Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Transmission and Distribution Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(4.3)
Transmission and Distribution Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0
Transmission and Distribution Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0
Transmission and Distribution Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0
Transmission and Distribution Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0
Transmission and Distribution Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0
Generation & Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		54.9		52.5		49.2
Generation & Marketing Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation & Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation & Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation & Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation & Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1.1		8.7		2
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		3.3		13.2		10.6
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(4.3)		0		4.9
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		0.2		0.4
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0.6
Sales to AEP Affiliates [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		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		2.4		0
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		8.2		(0.9)
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		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		0.9
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		0
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.4
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		2
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		0.4
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
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
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
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(3.3)
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		(0.4)
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		(0.4)
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		(0.6)
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		(0.4)
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		(0.5)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(3.3)
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		(0.7)
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		(0.4)
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		(0.5)
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		(0.4)
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		(0.4)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(0.9)		(11.4)		(2.4)
Regulatory Assets [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	3.4		(4.1)		0
Regulatory Assets [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(2.7)		(0.5)		0
Regulatory Assets [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	0		0		(5.8)
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	0.6		(1)		2.9
Regulatory Assets [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(4.3)		(1.1)		0.4
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	30.2		193.2		(5)
Regulatory Liabilities [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	28.7		49.6		(0.3)
Regulatory Liabilities [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	7.5		37.4		(9.1)
Regulatory Liabilities [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(24.7)		86		2.9
Regulatory Liabilities [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	4.4		0.3		1
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	$ 15.1		$ 16.9		$ 1.5
[1]	Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
[2]	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
[3]	The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts.
[4]	The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts.
[5]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[6]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
[7]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[9]	Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[10]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[11]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[12]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[13]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					$ 19,572.7	$ 18,512.4	[1],[2]
Long-term Debt, Fair Value					21,201.3	20,960.5	[3]
Other Temporary Investments
Cost					375.8	373.3
Gross Unrealized Gains					11.7	12.3
Gross Unrealized Losses					(0.7)	0
Estimated Fair Value					386.8	385.6
Debt and Equity Securities Within Other Temporary Investments [Abstract]
Proceeds From Investment Sales		$ 0	$ 0	$ 0
Purchases of Investments		10.7	1.6	17.4
Gross Realized Gains on Investment Sales		0	0	0
Gross Realized Losses on Investment Sales		0	0	0
Nuclear Trust Fund Investments
Estimated Fair Value		2,106.4	2,095.7		2,106.4	2,095.7
Gross Unrealized Gains					611.8	649.1
Other-Than-Temporary Impairments					(83.3)	(85.5)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,218.4	1,031.8	858.4
Purchases of Investments		2,272	1,086.4	910
Gross Realized Gains on Investment Sales		69.1	32.3	18.3
Gross Realized Losses on Investment Sales		53	15.4	8.1
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,106.4	2,095.7
Fair Value Measurements (Textuals) [Abstract]
Disposal Group, Including Discontinued Operation, Long-term Debt						83.2
Disposal Group, Including Discontinued Operation, Long-term Debt, Fair Value						114
Adjusted Cost of Debt Securities					771	903
Adjusted Cost of Domestic Equity Securities					555	524
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					3,930.7	3,958.7
Long-term Debt, Fair Value					4,416.7	4,711.2
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					2,000	2,019.6
Long-term Debt, Fair Value					2,193.6	2,255.1
Nuclear Trust Fund Investments
Estimated Fair Value		2,106.4	2,095.7		2,106.4	2,095.7
Gross Unrealized Gains					611.8	649.1
Other-Than-Temporary Impairments					(83.3)	(85.5)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,218.4	1,031.8	858.4
Purchases of Investments		2,272	1,086.4	910
Gross Realized Gains on Investment Sales		69.1	32.3	18.3
Gross Realized Losses on Investment Sales		53	15.4	$ 8.1
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,106.4	2,095.7
Fair Value Measurements (Textuals) [Abstract]
Adjusted Cost of Debt Securities					771	903
Adjusted Cost of Domestic Equity Securities					555	524
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					2,157.7	2,286.8
Long-term Debt, Fair Value					2,472.7	2,709.5
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					1,286.1	1,036.7
Long-term Debt, Fair Value					1,402.9	1,216.2
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					2,273.5	2,132.4
Long-term Debt, Fair Value					2,417.2	2,402.6
Cash [Member]
Other Temporary Investments
Cost	[4]				271	279.7
Gross Unrealized Gains	[4]				0	0
Gross Unrealized Losses	[4]				0	0
Estimated Fair Value	[4],[5]				271	279.7
Nuclear Trust Fund Investments
Estimated Fair Value	[6]	168.3	20		168.3	20
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	168.3	20
Cash [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[6]	168.3	20		168.3	20
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	168.3	20
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		811.2	953.3		811.2	953.3
Gross Unrealized Gains					40.2	50.3
Other-Than-Temporary Impairments					(4)	(6.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		811.2	953.3
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		811.2	953.3		811.2	953.3
Gross Unrealized Gains					40.2	50.3
Other-Than-Temporary Impairments					(4)	(6.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		811.2	953.3
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost					91.1	80.5
Gross Unrealized Gains					0	0
Gross Unrealized Losses					(0.7)	0
Estimated Fair Value					90.4	80.5
Domestic [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[7]	1,126.9	1,122.4		1,126.9	1,122.4
Gross Unrealized Gains					571.6	598.8
Other-Than-Temporary Impairments					(79.3)	(79.2)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	1,126.9	1,122.4
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[7]	1,126.9	1,122.4		1,126.9	1,122.4
Gross Unrealized Gains					571.6	598.8
Other-Than-Temporary Impairments					(79.3)	(79.2)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	1,126.9	1,122.4
Mutual Funds Equity [Member]
Other Temporary Investments
Cost					13.7	13.1
Gross Unrealized Gains					11.7	12.3
Gross Unrealized Losses					0	0
Estimated Fair Value	[7]				25.4	25.4
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		168.3	20		168.3	20
Gross Unrealized Gains					0	0
Other-Than-Temporary Impairments					0	0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		168.3	20
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		168.3	20		168.3	20
Gross Unrealized Gains					0	0
Other-Than-Temporary Impairments					0	0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		168.3	20
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		731.1	697		731.1	697
Gross Unrealized Gains					35.9	44.6
Other-Than-Temporary Impairments					(2.6)	(5)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		731.1	697
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		731.1	697		731.1	697
Gross Unrealized Gains					35.9	44.6
Other-Than-Temporary Impairments					(2.6)	(5)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		731.1	697
Corporate Debt Securities [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		57.9	47.8		57.9	47.8
Gross Unrealized Gains					3.2	4.5
Other-Than-Temporary Impairments					(1.1)	(1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		57.9	47.8
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		57.9	47.8		57.9	47.8
Gross Unrealized Gains					3.2	4.5
Other-Than-Temporary Impairments					(1.1)	(1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		57.9	47.8
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		22.2	208.5		22.2	208.5
Gross Unrealized Gains					1.1	1.2
Other-Than-Temporary Impairments					(0.3)	(0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		22.2	208.5
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		22.2	208.5		22.2	208.5
Gross Unrealized Gains					1.1	1.2
Other-Than-Temporary Impairments					(0.3)	$ (0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		22.2	$ 208.5
Within One Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		167.2			167.2
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		167.2
Within One Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		167.2			167.2
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		167.2
One Year To Five Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		361			361
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		361
One Year To Five Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		361			361
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		361
Five Year To Ten Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		129.4			129.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		129.4
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		129.4			129.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		129.4
After 10 years [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		153.6			153.6
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		153.6
After 10 years [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		153.6			$ 153.6
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		$ 153.6
[1]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
[2]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[3]	Amount excludes $114 million of fair value of Long-term Debt related to AEPRO.
[4]	Primarily represents amounts held for the repayment of debt.
[5]	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 investment in money market funds.
[6]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[7]	Amounts represent publicly traded equity securities and equity-based mutual funds.

Fair Value Financial Assets Lia

Fair Value Financial Assets Liabilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)$ / MWh		Dec. 31, 2014USD ($)$ / MWh		Dec. 31, 2013USD ($)
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 176.4		$ 162.5
Other Temporary Investments		386.8		385.6
Risk Management Assets
Risk Management Assets		456.2		472.1
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,106.4		2,095.7
Total Assets		3,125.8		3,115.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		266.2		222.5
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		150.8		117.9		$ 85.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	13.5		90		(9.2)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	53.7		0.7		37.5
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(4.9)		5.7		(2.5)
Purchases, Issuances and Settlements	[4]	(63)		(108.7)		(15.8)
Transfers into Level 3	[5],[6]	28.7		(7.6)		19
Transfers out of Level 3	[6],[7]	(18.9)		(21.5)		(3.6)
Transfer of OPCo Generation to Parent						0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	(13)		74.3		7.1
Ending Balance		$ 146.9		$ 150.8		117.9
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk	[9]	6.70%		3.03%
Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 3.9		$ 17.2
Other Temporary Investments		345.8		339.7
Risk Management Assets
Risk Management Assets		11.5		37.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,287.4		1,131.8
Total Assets		1,648.6		1,526.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		24.1		65.3
Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	4.3		0.9
Other Temporary Investments		7.7		9.1
Risk Management Assets
Risk Management Assets		510.9		560.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
Total Assets		1,334.1		1,524.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		493.8		466.3
Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Other Temporary Investments		0		0
Risk Management Assets
Risk Management Assets		220.7		190.3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		220.7		190.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		73.8		39.5
Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	168.2		144.4
Other Temporary Investments		33.3		36.8
Risk Management Assets
Risk Management Assets		(286.9)		(316.8)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7.8		10.6
Total Assets		(77.6)		(125)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		(325.5)		(348.6)
2015 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				(18)
2015 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				31
2015 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				50
2016 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		(9)
2016 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		2
2016 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		28
2016 - 2018 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				(10)
2016 - 2018 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				52
2016 - 2018 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				29
2017 - 2019 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		(4)
2017 - 2019 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		18
2017 - 2019 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		29
2019 - 2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				12
2019 - 2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				9
2020 - 2021 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		4
2020 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		19
2021 - 2030 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				1
2021 - 2030 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				66
2022 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		76
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10]	438.5	[11]	452.7	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	236.6	[11]	198.4	[12]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10]	11.5	[11]	37.7	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	24.1	[11]	65.3	[12]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10]	495	[11]	528.4	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	471.5	[11]	431.9	[12]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10]	219.7	[11]	190.3	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	67.3	[11]	36.7	[12]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10]	(287.7)	[11]	(303.7)	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	(326.3)	[11]	(335.5)	[12]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		212.3		157.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 70.3		$ 37
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	9.69		11.37
Forward Price Range High | $ / MWh	[13]	165.36		159.92
Weighted Average Market Price | $ / MWh	[13]	36.35		57.18
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 8.4		$ 33
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 3.5		$ 2.5
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(6.99)		(14.63)
Forward Price Range High | $ / MWh	[13]	10.34		20.02
Weighted Average Market Price | $ / MWh	[13]	1.10		0.96
Commodity [Member]
Risk Management Assets
Risk Management Assets	[10]	$ 17.6		$ 16.8
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	26.1		14.3
Commodity [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	0		0
Commodity [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10]	15.9		31.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	18.9		26.6
Commodity [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10]	1		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	6.5		2.8
Commodity [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10]	0.7		(15.1)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	0.7		(15.1)
Interest Rate Foreign Currency Hedges [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0.4		1
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0.4		1
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Interest Rate Foreign Currency Hedges [Member] | Other [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Fair Value Hedging [Member]
Risk Management Assets
Risk Management Assets		0.1		2.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		3.1		8.8
Fair Value Hedging [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Fair Value Hedging [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		0		0.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		3		6.8
Fair Value Hedging [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Fair Value Hedging [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0.1		2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0.1		2
Appalachian Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	14.9		15.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		30.6		44.3
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		15.8	[14]	10.6		11
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	2.1	[14]	29.7		(3.6)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0	[14]	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0	[14]	0		0
Purchases, Issuances and Settlements	[4]	(17.2)	[14]	(32.6)		0.5
Transfers into Level 3	[5],[6]	0	[14]	(3.6)		1.3
Transfers out of Level 3	[6],[7]	1.2	[14]	0		(0.9)
Transfer of OPCo Generation to Parent						0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	9.8	[14]	11.7		2.3
Ending Balance		11.7	[14]	15.8	[14]	10.6
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	14.8		15.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15		15.8
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		13.9		20.2
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Risk Management Assets
Risk Management Assets		12.2		17.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		12.2		17.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0.5		1.9
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0.1		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(10.5)		(9.4)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	15.7		28.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	4.9		13.1
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.2		0.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.2		0.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	13.9		20.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	17.8		20.4
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	12.2		17.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.5		1.9
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	(10.6)		(9.4)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	(13.6)		(9.4)
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		7.9		5.8
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.2		$ 1.8
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	12.61		13.43
Forward Price Range High | $ / MWh	[13]	47.24		123.02
Weighted Average Market Price | $ / MWh	[13]	32.38		52.47
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 4.3		$ 11.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.3		$ 0.1
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(6.96)		(14.63)
Forward Price Range High | $ / MWh	[13]	8.43		20.02
Weighted Average Market Price | $ / MWh	[13]	1.34		1.01
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,106.4		$ 2,095.7
Total Assets		2,118.7		2,121.3
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		14.7	[14]	7.2		7.5
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	0.2	[14]	18.6		(2.4)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0	[14]	0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0	[14]	0		0
Purchases, Issuances and Settlements	[4]	(14.2)	[14]	(20.6)		0.4
Transfers into Level 3	[5],[6]	0	[14]	(2.5)		0.9
Transfers out of Level 3	[6],[7]	0.8	[14]	0		(0.6)
Transfer of OPCo Generation to Parent						0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	2.8	[14]	12		1.4
Ending Balance		4.3	[14]	14.7	[14]	7.2
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,287.4		1,131.8
Total Assets		1,287.5		1,131.9
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
Total Assets		828.2		969.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		6.3		16
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		6.3		16
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		2		1.3
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		7.8		10.6
Total Assets		(3.3)		4.2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	12.3		25.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	7.9		6.6
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.1		0.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.1		0.2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	17		15.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	17.5		11.4
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	6.3		16
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	2		1.3
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	(11.1)		(6.4)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	(11.7)		(6.3)
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		6		6.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.2		$ 1.2
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	12.61		13.43
Forward Price Range High | $ / MWh	[13]	47.24		123.02
Weighted Average Market Price | $ / MWh	[13]	32.38		52.47
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0.3		$ 9.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 1.8		$ 0.1
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(6.96)		(14.63)
Forward Price Range High | $ / MWh	[13]	8.43		20.02
Weighted Average Market Price | $ / MWh	[13]	1.34		1.01
Ohio Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 27.7		$ 28.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		46.9		81
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		48.4		2.9		15.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	0.5		30.8		(5)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0.3
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Purchases, Issuances and Settlements	[4]	(6.7)		(33.7)		0.8
Transfers into Level 3	[5],[6]	0		0		1.9
Transfers out of Level 3	[6],[7]	0		0		(1.3)
Transfer of OPCo Generation to Parent						(12.1)
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	(26.3)		48.4		2.9
Ending Balance		15.9		48.4		2.9
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0.4
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		0.4
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		0
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Risk Management Assets
Risk Management Assets				52.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16		52.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				3.9
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	27.7		28.3
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		30.9		28.3
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	19.2		52.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	3.6		4.9
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.8		1.1
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	16		52.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.1		3.9
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	3.2		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	2.7		(0.1)
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		16		45.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.1		$ 3.9
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	41.61		48.25
Forward Price Range High | $ / MWh	[13]	165.36		159.92
Weighted Average Market Price | $ / MWh	[13]	86.84		84.04
Ohio Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets				$ 7.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				$ 0
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]			(14.63)
Forward Price Range High | $ / MWh	[13]			20.02
Weighted Average Market Price | $ / MWh	[13]			1.01
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ (0.3)		$ 0		0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(0.2)		0		0
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Purchases, Issuances and Settlements	[4]	0.6		0		0
Transfers into Level 3	[5],[6]	0		0		0
Transfers out of Level 3	[6],[7]	0		0		0
Transfer of OPCo Generation to Parent						0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	0.5		(0.3)		0
Ending Balance		0.6		(0.3)		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.6		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.2		0.9
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.5		0.6
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.7		0.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.1		0.7
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	(0.1)		(0.4)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	(0.4)		(0.4)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.7		0.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.1		$ 0.7
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(6.96)		(14.63)
Forward Price Range High | $ / MWh	[13]	8.43		20.02
Weighted Average Market Price | $ / MWh	[13]	1.34		1.01
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 5.2		$ 14.4
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		6		14.4
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		(0.5)		0		0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	9.2		0		0
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
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Purchases, Issuances and Settlements	[4]	(8.7)		0		0
Transfers into Level 3	[5],[6]	0		0		0
Transfers out of Level 3	[6],[7]	0		0		0
Transfer of OPCo Generation to Parent						0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	0.8		(0.5)		0
Ending Balance		0.8		(0.5)		$ 0
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	3.6		12.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		3.6		12.7
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		0
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.9		0.4
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	1.6		1.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		1.5		1.3
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.8		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	5.2		1.1
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0		0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	5.5		0.7
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	0.9		0.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	0.1		0.9
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[10],[15]	(0.1)		(0.4)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10],[15]	(0.4)		(0.5)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.9		0.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.1		$ 0.9
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(6.96)		(14.63)
Forward Price Range High | $ / MWh	[13]	8.43		20.02
Weighted Average Market Price | $ / MWh	[13]	1.34		1.01
Cash [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1],[16]	$ 271		$ 279.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	168.3		20
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	230		233.8
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	160.5		9.4
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	7.7		9.1
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	33.3		36.8
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	7.8		10.6
Cash [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	168.3		20
Cash [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	160.5		9.4
Cash [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	0		0
Cash [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[17]	7.8		10.6
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		811.2		953.3
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
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
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		90.4		80.5
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		90.4		80.5
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	1,126.9		1,122.4
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	1,126.9		1,122.4
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	1,126.9		1,122.4
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	1,126.9		1,122.4
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[18]	0		0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[18]	25.4		25.4
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[18]	25.4		25.4
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[18]	0		0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[18]	0		0
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[18]	0		0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		168.3		20
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		168.3		20
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		731.1		697
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		731.1		697
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		731.1		697
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		731.1		697
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
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
Corporate Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.9		47.8
Corporate Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.9		47.8
Corporate Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.9		47.8
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		57.9		47.8
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		22.2		208.5
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		22.2		208.5
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		22.2		208.5
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		22.2		208.5
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
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
[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 investment 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 the settlement of risk management commodity contracts for the reporting period.
[5]	Represents existing assets or liabilities that were previously categorized as Level 2.
[6]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[7]	Represents existing assets or liabilities that were previously categorized as Level 3.
[8]	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
[9]	Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[10]	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.”
[11]	The December 31, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(9) million in 2016 and $(4) million in periods 2017-2019; Level 2 matures $2 million in 2016, $18 million in periods 2017-2019 and $4 million in periods 2020-2021; Level 3 matures $28 million in 2016, $29 million in periods 2017-2019, $19 million in periods 2020-2021 and $76 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts.
[12]	The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and $(10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts.
[13]	Represents market prices in dollars per MWh.
[14]	Includes both affiliated and nonaffiliated transactions.
[15]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[16]	Primarily represents amounts held for the repayment of debt.
[17]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[18]	Amounts represent publicly traded equity securities and equity-based mutual funds.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended											12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Federal:
Current												$ 107.3	$ 22.8	$ (53.4)
Deferred												774.8	800.1	678.6
Total Federal												882.1	822.9	625.2
State and Local:
Current												14.5	22.8	28.7
Deferred												23	56.9	23.8
Total State and Local												37.5	79.7	52.5
Income Tax Expense:
Deferred												808.2	868.8	711.2
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	$ 470.7		$ 519.6	$ 431.3	$ 630.7	$ 191.5	[1]	$ 494.4	$ 391.1	$ 561		2,052.3	1,638	1,484.2
Discontinued Operations	(265.5)	[2]	(7.8)	0.1	(10.5)	(31.9)		(10.2)	(2.7)	(2.7)		(283.7)	(47.5)	(10.3)
Income Tax Expense (Credit)												919.6	902.6	677.7
Pretax Income												2,688.2	2,493.1	2,151.6
Income Taxes on Pretax Income at Statutory Rate (35%)												940.9	872.6	753.1
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												53.6	54	46.6
Investment Tax Credits, Net												(11.6)	(12.8)	(14)
State and Local Income Taxes, Net												24.4	54.3	29.1
Removal Costs												(28.8)	(23.9)	(20.9)
AFUDC												(51.6)	(41.8)	(30.5)
Valuation Allowance												17.2	(2.5)	5.1
U.K. Windfall Tax												0	0	(79.5)
Other												(24.5)	2.7	(11.3)
Income Tax Expense (Credit)												$ 919.6	$ 902.6	$ 677.7
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												34.20876%	36.20392%	31.49749%
Deferred Tax Assets	2,503.9					2,650.7						$ 2,503.9	$ 2,650.7
Deferred Tax Liabilities	(14,237.1)					(13,503.1)						(14,237.1)	(13,503.1)
Property Related Temporary Differences	(8,533.3)					(7,883.4)						(8,533.3)	(7,883.4)
Amounts Due from Customers for Future Federal Income Taxes	(263.5)					(255.2)						(263.5)	(255.2)
Deferred State Income Taxes	(872)					(796.9)						(872)	(796.9)
Securitized Assets	(633.2)					(753.2)						(633.2)	(753.2)
Regulatory Assets	(873.6)					(694.1)						(873.6)	(694.1)
Deferred Income Taxes on Other Comprehensive Loss	72.2					59.7						72.2	59.7
Accrued Nuclear Decommissioning	(614.6)					(611)						(614.6)	(611)
Net Operating Loss Carryforward	39.6					46.4						39.6	46.4
Tax Credit Carryforward	85					144.3						85	144.3
Valuation Allowance	(130)					(55.6)						(130)	(55.6)
All Other, Net	(9.8)					(53.4)						(9.8)	(53.4)
Net Deferred Tax Liabilities	(11,733.2)					(10,852.4)						(11,733.2)	(10,852.4)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												2.7	2.9	$ 1.5
Interest Income												0.8	1.2	51.8
Reversal of Prior Period Interest Expense												0	2	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	44.7					44						44.7	44
Accrual for Payment of Interest and Penalties	7.2					5.9						7.2	5.9
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					182					175.2		182	175.2	267.2
Increase - Tax Positions Taken During a Prior Period												5.4	18.2	0
Decrease - Tax Positions Taken During a Prior Period												(0.4)	(1.5)	(93.6)
Increase - Tax Positions Taken During the Current Year												0	0	1.8
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	(0.6)	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(9.3)	(0.2)
Balance at December 31,	187					182						187	182	175.2	$ 267.2
Unrecognized Tax Benefits, if Recognized - Amount	100.2					97.2						$ 100.2	97.2	86.9
Income Taxes (Textuals) [Abstract]
Discontinued Operations													$ 39	$ 5.9
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss															366	$ 226
Income Tax Expense (Credit)												$ 919.6	$ 902.6	$ 677.7
Interest Income												7.9	7.4	57.9
Net Income (Loss)	470.7		519.6	431.3	630.7	191.5	[1]	494.4	391.1	561		$ 2,052.3	$ 1,638	1,484.2
Period With No Receipt Of Cash Expected												12 months
Period with No Change in Unrecognized Tax Benefits												12 months
Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Original WV Corporate Income Tax Rate													7.00%
Reduced WV Corporate Income Tax													6.50%
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Valuation Allowance Expiration Of Charitable Contribution Carryforward Deductions	17											$ 17
Valuation Allowance Excess Tax Basis Of Stock Over Book Value	156											156
Valuation Allowance Realized Capital Losses From Sale	48											48
Valuation Allowance	(130)					(55.6)						(130)	$ (55.6)
Appalachian Power Co [Member]
Income Tax Expense:
Current												(32.9)	10.9	58.4
Deferred												227.5	144.7	75.7
Deferred Investment Tax Credits												(0.3)	(0.7)	(1.2)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	65.2		74.6	59	141.8	28.6		48.8	36.2	101.8		340.6	215.4	193.2
Discontinued Operations	0		0	0	0	0		0	0	0
Income Tax Expense (Credit)												194.3	154.9	132.9
Pretax Income												534.9	370.3	326.1
Income Taxes on Pretax Income at Statutory Rate (35%)												187.2	129.6	114.1
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												19.8	23.5	20.3
Investment Tax Credits, Net												(0.3)	(0.6)	(1.2)
State and Local Income Taxes, Net												7.2	6.5	2.7
Removal Costs												(9.9)	(6.8)	(6.5)
AFUDC												(7)	(3.8)	(1.4)
Valuation Allowance												1.7	(2.5)	5.1
Other												(4.4)	9	(0.2)
Income Tax Expense (Credit)												$ 194.3	$ 154.9	$ 132.9
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												36.32455%	41.83095%	40.75437%
Deferred Tax Assets	412.9					446.4						$ 412.9	$ 446.4
Deferred Tax Liabilities	(2,939.9)					(2,711.2)						(2,939.9)	(2,711.2)
Property Related Temporary Differences	(1,866)					(1,801.9)						(1,866)	(1,801.9)
Amounts Due from Customers for Future Federal Income Taxes	(68.2)					(70.4)						(68.2)	(70.4)
Deferred State Income Taxes	(308.7)					(239.7)						(308.7)	(239.7)
Securitized Assets	(114.8)					(122.6)						(114.8)	(122.6)
Regulatory Assets	(169.1)					(113.7)						(169.1)	(113.7)
Deferred Income Taxes on Other Comprehensive Loss	1.5					(2.7)						1.5	(2.7)
Net Operating Loss Carryforward	1					9.8						1	9.8
Tax Credit Carryforward	19.2					46.2						19.2	46.2
All Other, Net	(21.9)					30.2						(21.9)	30.2
Net Deferred Tax Liabilities	(2,527)					(2,264.8)						(2,527)	(2,264.8)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.4	0	$ 0
Interest Income												0	0	1.1
Reversal of Prior Period Interest Expense												0	0.2	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0					0						0	0
Accrual for Payment of Interest and Penalties	0					0						0	0
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					0					1.2		0	1.2	5.3
Increase - Tax Positions Taken During a Prior Period												0.3	0	0
Decrease - Tax Positions Taken During a Prior Period												0	0	(4.1)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(1.2)	0
Balance at December 31,	0.3					0						0.3	0	1.2	5.3
Unrecognized Tax Benefits, if Recognized - Amount	0.2					0						$ 0.2	$ 0	$ 0
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss																313
Income Tax Expense (Credit)												$ 194.3	$ 154.9	$ 132.9
Net Income (Loss)	65.2		74.6	59	141.8	28.6		48.8	36.2	101.8		$ 340.6	$ 215.4	193.2
Period with No Change in Unrecognized Tax Benefits												12 months
Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Original WV Corporate Income Tax Rate													7.00%
Reduced WV Corporate Income Tax													6.50%
Indiana Michigan Power Co [Member]
Income Tax Expense:
Current												$ 5.2	$ 14.3	(49.1)
Deferred												94.2	70.2	129.1
Deferred Investment Tax Credits												(3.3)	(4.9)	(4.9)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	24.9		56.6	50.6	72.7	14.6		26.6	27.3	87.1		204.8	155.6	177.5
Discontinued Operations	0		0	0	0	0		0	0	0
Income Tax Expense (Credit)												96.1	79.6	75.1
Pretax Income												300.9	235.2	252.6
Income Taxes on Pretax Income at Statutory Rate (35%)												105.3	82.3	88.4
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												9.5	12.9	10.1
Investment Tax Credits, Net												(3.3)	(4.9)	(4.9)
State and Local Income Taxes, Net												5.8	7.7	(0.9)
Removal Costs												(12.6)	(11.3)	(9.4)
AFUDC												(6.2)	(10)	(10.6)
Other												(2.4)	2.9	2.4
Income Tax Expense (Credit)												$ 96.1	$ 79.6	$ 75.1
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												31.93752%	33.84354%	29.7308%
Deferred Tax Assets	837.4					911.8						$ 837.4	$ 911.8
Deferred Tax Liabilities	(2,198.9)					(2,190)						(2,198.9)	(2,190)
Property Related Temporary Differences	(521.6)					(418.7)						(521.6)	(418.7)
Amounts Due from Customers for Future Federal Income Taxes	(42.7)					(40.6)						(42.7)	(40.6)
Deferred State Income Taxes	(124.8)					(138.9)						(124.8)	(138.9)
Regulatory Assets	(70.2)					(74.7)						(70.2)	(74.7)
Deferred Income Taxes on Other Comprehensive Loss	9					7.7						9	7.7
Accrued Nuclear Decommissioning	(614.6)					(611)						(614.6)	(611)
All Other, Net	3.4					(2)						3.4	(2)
Net Deferred Tax Liabilities	(1,361.5)					(1,278.2)						(1,361.5)	(1,278.2)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.2	0	$ 0
Interest Income												0	0	0.6
Reversal of Prior Period Interest Expense												0	0.3	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0					0						0	0
Accrual for Payment of Interest and Penalties	0.6					0.5						0.6	0.5
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					2.3					3.2		2.3	3.2	15.1
Increase - Tax Positions Taken During a Prior Period												0.1	1.4	0
Decrease - Tax Positions Taken During a Prior Period												0	0	(11.9)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	(0.7)	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(1.6)	0
Balance at December 31,	2.4					2.3						2.4	2.3	3.2	15.1
Unrecognized Tax Benefits, if Recognized - Amount	1.6					1.6						$ 1.6	$ 1.6	$ 1.2
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss																$ 123
Income Tax Expense (Credit)												$ 96.1	$ 79.6	$ 75.1
Net Income (Loss)	24.9		56.6	50.6	72.7	14.6		26.6	27.3	87.1		$ 204.8	$ 155.6	177.5
Period with No Change in Unrecognized Tax Benefits												12 months
Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Original WV Corporate Income Tax Rate													7.00%
Reduced WV Corporate Income Tax													6.50%
Ohio Power Co [Member]
Income Tax Expense:
Current												$ 89	$ 58.1	92.6
Deferred												37.6	74.4	134.5
Deferred Investment Tax Credits												(0.1)	(0.3)	(1.4)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	48		71.6	47.7	65.4	45		54.1	56.5	60.8		232.7	216.4	410
Discontinued Operations	0		0	0	0	0		0	0	0
Income Tax Expense (Credit)												126.5	132.2	225.7
Pretax Income												359.2	348.6	635.7
Income Taxes on Pretax Income at Statutory Rate (35%)												125.7	122	222.5
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												8.2	6.7	6.8
Investment Tax Credits, Net												(0.1)	(0.2)	(1.4)
State and Local Income Taxes, Net												0.7	8.8	3.3
Other												(8)	(5.1)	(5.5)
Income Tax Expense (Credit)												$ 126.5	$ 132.2	$ 225.7
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												35.21715%	37.92312%	35.50417%
Deferred Tax Assets	162.4					171.8						$ 162.4	$ 171.8
Deferred Tax Liabilities	(1,545.6)					(1,528.1)						(1,545.6)	(1,528.1)
Property Related Temporary Differences	(1,022.8)					(926.5)						(1,022.8)	(926.5)
Amounts Due from Customers for Future Federal Income Taxes	(44.6)					(47.6)						(44.6)	(47.6)
Deferred State Income Taxes	(34.4)					(34.2)						(34.4)	(34.2)
Regulatory Assets	(220)					(242.4)						(220)	(242.4)
Deferred Income Taxes on Other Comprehensive Loss	(2.3)					(3)						(2.3)	(3)
Deferred Fuel and Purchased Power	(117.4)					(145.5)						(117.4)	(145.5)
All Other, Net	58.3					42.9						58.3	42.9
Net Deferred Tax Liabilities	(1,383.2)					(1,356.3)						(1,383.2)	(1,356.3)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												1	0.1	$ 0
Interest Income												0	0	1.9
Reversal of Prior Period Interest Expense												0	0.2	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0					0						0	0
Accrual for Payment of Interest and Penalties	0.6					0.4						0.6	0.4
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					6.9					2.1		6.9	2.1	11.1
Increase - Tax Positions Taken During a Prior Period												0	6.4	0
Decrease - Tax Positions Taken During a Prior Period												0	0	(9)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(1.6)	0
Balance at December 31,	6.9					6.9						6.9	6.9	2.1	11.1
Unrecognized Tax Benefits, if Recognized - Amount	4.5					4.5						$ 4.5	$ 4.5	$ 0.7
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Income Tax Expense (Credit)												$ 126.5	$ 132.2	$ 225.7
Net Income (Loss)	48		71.6	47.7	65.4	45		54.1	56.5	60.8		$ 232.7	$ 216.4	410
Period with No Change in Unrecognized Tax Benefits												12 months
Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Original WV Corporate Income Tax Rate													7.00%
Reduced WV Corporate Income Tax													6.50%
Public Service Co Of Oklahoma [Member]
Income Tax Expense:
Current												$ (6.4)	$ (24.2)	7.7
Deferred												58.3	74.7	53.8
Deferred Investment Tax Credits												(0.6)	0.1	4.4
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	7		44.7	27.1	13.7	10.9		45.1	22.5	8.4		92.5	86.9	97.8
Discontinued Operations	0		0	0	0	0		0	0	0
Income Tax Expense (Credit)												51.3	50.6	65.9
Pretax Income												143.8	137.5	163.7
Income Taxes on Pretax Income at Statutory Rate (35%)												50.3	48.1	57.3
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												0.5	0.2	0.2
Investment Tax Credits, Net												(1.8)	(0.8)	(0.8)
State and Local Income Taxes, Net												5.1	4.8	5.4
AFUDC												(3.1)	(1.1)	(1.5)
Tax Adjustments												(0.3)	(1.2)	5.3
Other												0.6	0.6	0
Income Tax Expense (Credit)												$ 51.3	$ 50.6	$ 65.9
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												35.67455%	36.80%	40.25657%
Deferred Tax Assets	141.2					110.7						$ 141.2	$ 110.7
Deferred Tax Liabilities	(1,113)					(1,016.7)						(1,113)	(1,016.7)
Property Related Temporary Differences	(861.9)					(805.2)						(861.9)	(805.2)
Amounts Due from Customers for Future Federal Income Taxes	(2.2)					(0.7)						(2.2)	(0.7)
Deferred State Income Taxes	(117)					(109.3)						(117)	(109.3)
Regulatory Assets	(54.3)					(39.6)						(54.3)	(39.6)
Deferred Income Taxes on Other Comprehensive Loss	(2.3)					(2.7)						(2.3)	(2.7)
Deferred Federal Income Taxes on Deferred State Income Taxes	46.6					43.9						46.6	43.9
Net Operating Loss Carryforward	7.1					6.4						7.1	6.4
Tax Credit Carryforward	0.6					0.7						0.6	0.7
All Other, Net	11.6					0.5						11.6	0.5
Net Deferred Tax Liabilities	(971.8)					(906)						(971.8)	(906)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.1	0.1	$ 0
Interest Income												0	0	0.1
Reversal of Prior Period Interest Expense												0	0.1	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0					0						0	0
Accrual for Payment of Interest and Penalties	0.4					0.3						0.4	0.3
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					1.3					2.2		1.3	2.2	2.3
Increase - Tax Positions Taken During a Prior Period												0	0	0
Decrease - Tax Positions Taken During a Prior Period												0	0	(0.1)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(0.9)	0
Balance at December 31,	1.3					1.3						1.3	1.3	2.2	2.3
Unrecognized Tax Benefits, if Recognized - Amount	0.9					0.9						$ 0.9	$ 0.9	$ 0.8
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Income Tax Expense (Credit)												$ 51.3	$ 50.6	$ 65.9
Net Income (Loss)	7		44.7	27.1	13.7	10.9		45.1	22.5	8.4		$ 92.5	86.9	97.8
Period with No Change in Unrecognized Tax Benefits												12 months
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Southwestern Electric Power Co [Member]
Income Tax Expense:
Current												$ 44.3	(171.6)	(10.9)
Deferred												41.9	239.4	81.9
Deferred Investment Tax Credits												(1.4)	(1.4)	(1.5)
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	7.7		82.1	59.5	46.7	14.2		74.6	32.8	23		196	144.6	153.8
Discontinued Operations	0		0	0	0	0		0	0	0
Income Tax Expense (Credit)												84.8	66.4	69.5
Pretax Income												280.8	211	223.3
Income Taxes on Pretax Income at Statutory Rate (35%)												98.3	73.8	78.1
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												3.1	2.9	3.1
Depletion												(5.5)	(4.1)	(3.5)
Investment Tax Credits, Net												(1.4)	(1.4)	(1.5)
State and Local Income Taxes, Net												4.8	3.1	(1.4)
AFUDC												(9.2)	(4.2)	(2.4)
Other												(5.3)	(3.7)	(2.9)
Income Tax Expense (Credit)												$ 84.8	$ 66.4	$ 69.5
Net Deferred Tax Liability and Significant Temporary Differences
Effective Income Tax Rate												30.19943%	31.46919%	31.12405%
Deferred Tax Assets	194.7					186.1						$ 194.7	$ 186.1
Deferred Tax Liabilities	(1,594.5)					(1,528.2)						(1,594.5)	(1,528.2)
Property Related Temporary Differences	(1,275.1)					(1,235.1)						(1,275.1)	(1,235.1)
Amounts Due from Customers for Future Federal Income Taxes	(47.8)					(44.1)						(47.8)	(44.1)
Deferred State Income Taxes	(132.3)					(124.1)						(132.3)	(124.1)
Regulatory Assets	(26.1)					(19.4)						(26.1)	(19.4)
Deferred Income Taxes on Other Comprehensive Loss	5					4						5	4
Impairment Loss	20.7					21.1						20.7	21.1
Net Operating Loss Carryforward	19.7					21.9						19.7	21.9
All Other, Net	36.1					33.6						36.1	33.6
Net Deferred Tax Liabilities	(1,399.8)					(1,342.1)						(1,399.8)	(1,342.1)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.4	0.2	$ 0.2
Interest Income												0	0	0
Reversal of Prior Period Interest Expense												0	0.2	0
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0					0						0	0
Accrual for Payment of Interest and Penalties	1.4					1						1.4	1
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,					7.5					7.6		7.5	7.6	9.5
Increase - Tax Positions Taken During a Prior Period												1.8	1.6	0
Decrease - Tax Positions Taken During a Prior Period												0	(0.8)	(3.2)
Increase - Tax Positions Taken During the Current Year												0	0	1.3
Decrease - Tax Positions Taken During the Current Year												0	0	0
Increase - Settlements with Taxing Authorities												0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	(0.9)	0
Balance at December 31,	9.3					7.5						9.3	7.5	7.6	9.5
Unrecognized Tax Benefits, if Recognized - Amount	6					4.9						$ 6	$ 4.9	$ 4.4
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss															$ 858
Income Tax Expense (Credit)												$ 84.8	$ 66.4	$ 69.5
Net Income (Loss)	7.7		$ 82.1	$ 59.5	$ 46.7	14.2		$ 74.6	$ 32.8	$ 23		$ 196	144.6	153.8
Period with No Change in Unrecognized Tax Benefits												12 months
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Kentucky [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	80.7											$ 80.7
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2035
Louisiana [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	376.3											$ 376.3
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2030
Louisiana [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	375.7											$ 375.7
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2030
Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	378.1											$ 378.1
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2035
Oklahoma [Member] | Public Service Co Of Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	181.8											$ 181.8
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2035
Oklahoma [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	3.2											$ 3.2
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2035
West Virginia [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	49.9											$ 49.9
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2033
West Virginia [Member] | Appalachian Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	24.8											$ 24.8
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2033
West Virginia [Member] | Ohio Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	25.2											$ 25.2
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2033
Federal [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward														156
Tax Credit Carryforward
Tax Credit Carryforward, Amount	85											$ 85
Tax Credit Carryforward Amount To Expire If Not Used	47.8											47.8
Income Taxes (Textuals) [Abstract]
Uncertain Tax Positions Netted Against Operating Loss Carryforward														121
Uncertain Tax Position Noncurrent						69							69
Uncertain Tax Positions Netted Against Tax Credit and Alternative Minimum Tax Carryforward Tax Benefits	59					$ 52						$ 59	$ 52
Federal [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
Federal [Member] | Appalachian Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward														12
Tax Credit Carryforward
Tax Credit Carryforward, Amount	19.1											$ 19.1
Tax Credit Carryforward Amount To Expire If Not Used	5.8											$ 5.8
Federal [Member] | Appalachian Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Appalachian Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
Federal [Member] | Indiana Michigan Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward														13
Tax Credit Carryforward
Tax Credit Carryforward, Amount	3.7											$ 3.7
Tax Credit Carryforward Amount To Expire If Not Used	3.2											$ 3.2
Federal [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
Federal [Member] | Ohio Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	19.3											$ 19.3
Tax Credit Carryforward Amount To Expire If Not Used	1											$ 1
Federal [Member] | Ohio Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Ohio Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
Federal [Member] | Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0.6											$ 0.6
Tax Credit Carryforward Amount To Expire If Not Used	0.6											$ 0.6
Federal [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
Federal [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward														167
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0.7											$ 0.7
Tax Credit Carryforward Amount To Expire If Not Used	0.6											$ 0.6
Federal [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2035
Federal [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2030
State [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	23.4											$ 23.4
Tax Credit Carryforward Amount To Expire If Not Used	23.4											23.4
State [Member] | Appalachian Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Indiana Michigan Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Ohio Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Public Service Co Of Oklahoma [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	23.4											23.4
Tax Credit Carryforward Amount To Expire If Not Used	23.4											23.4
State [Member] | Southwestern Electric Power Co [Member]
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	$ 0											$ 0
Uk Windfall Tax Issue [Member]
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income														108
Income Tax Expense (Credit)											$ 80
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Income Tax Expense (Credit)											80
Income Taxes (Textuals) [Abstract]
Income Tax Expense (Credit)											80
Interest Income											$ 43
Net Income (Loss)														$ 108
American Taxpayer Relief Act Of 2012 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
American Taxpayer Relief Act Of 2012 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
American Taxpayer Relief Act Of 2012 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
American Taxpayer Relief Act Of 2012 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
American Taxpayer Relief Act Of 2012 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
American Taxpayer Relief Act Of 2012 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Tax Increase Prevention Act of 2014 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Tax Increase Prevention Act of 2014 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Tax Increase Prevention Act of 2014 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Tax Increase Prevention Act of 2014 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Tax Increase Prevention Act of 2014 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Protecting Americans from Tax Hikes Act of 2015 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension												50.00%
Bonus Depreciation Extension Phase Down 40												40.00%
Bonus Depreciation Extension Phase Down 30												30.00%
Solar Investment Tax Credit												30.00%
Net Tax Benefit [Member]
Income Taxes (Textuals) [Abstract]
Discontinued Operations												$ 6.2
[1]	Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4).
[2]	Includes sale of AEPRO (see Note 7).

Leases (Details)

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Lease Rental Costs
Net Lease Expense on Operating Leases		$ 292.6	$ 303.9		$ 326.6
Amortization of Capital Leases		108.5	109.4		73.9
Interest on Capital Leases		25.1	26.1		28.3
Total Lease Rental Costs	[1]	426.2	439.4		428.8
Lease Expenses Related to AEPRO		89	96		103
Net Property Under Capital Leases Related to AEPRO			179
Total Obligations Under Capital Lease Related to AEPRO			189
PP&E and Related Obligations Under Capital Leases
Generation		128.2	104.4
Other Property, Plant and Equipment		439.3	683
Total Property, Plant and Equipment Under Capital Leases		567.5	787.4
Accumulated Amortization		214.1	240
Net Property, Plant and Equipment Under Capital Leases		353.4	547.4	[2]
Noncurrent Liability		247.3	440.4
Liability Due Within One Year		96.2	111.4
Total Obligations Under Capital Leases		343.5	551.8	[2]
Future Minimum Lease Payments
Capital Leases, 2016		112.9
Noncancelable Operating Leases, 2016		239.1
Capital Leases, 2017		76.2
Noncancelable Operating Leases, 2017		228.7
Capital Leases, 2018		54.9
Noncancelable Operating Leases, 2018		219.9
Capital Leases, 2019		38.7
Noncancelable Operating Leases, 2019		211.2
Capital Leases, 2020		27.7
Noncancelable Operating Leases, 2020		202.8
Capital Leases, Later Years		110.7
Noncancelable Operating Leases, Later Years		452.3
Capital Leases, Total Future Minimum Lease Payments		421.1
Noncancelable Operating Leases, Total Future Minimum Lease Payments		1,554
Less Estimated Interest Element on Capital Leases		77.6
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		343.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		$ 33.4
Leases (Textuals) [Abstract]
Maximum Remaining Lease Term		34 years
Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,016	[3]	$ 147.8
2,017	[3]	147.8
2,018	[3]	147.8
2,019	[3]	147.8
2,020	[3]	147.8
Later Years	[3]	295
Total Future Minimum Lease Payments	[3]	$ 1,034
Leases (Textuals) [Abstract]
Lease Term		33 years
Boat and Barge Leases [Member]
Leases (Textuals) [Abstract]
Maximum Potential Loss Related to Guarantee		$ 16
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases		94
Sabine Dragline Lease [Member]
Leases (Textuals) [Abstract]
Cost of Electric Draglines to be Used for Mining Operations		47
Appalachian Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		16.4	18.3		17.5
Amortization of Capital Leases		5.6	5.5		6.3
Interest on Capital Leases		0.8	1		1.4
Total Lease Rental Costs		22.8	24.8		25.2
PP&E and Related Obligations Under Capital Leases
Generation		43.4	14.1
Other Property, Plant and Equipment		17.6	19.4
Total Property, Plant and Equipment Under Capital Leases		61	33.5
Accumulated Amortization		15.6	14
Net Property, Plant and Equipment Under Capital Leases		45.4	19.5
Noncurrent Liability		39.1	14.4
Liability Due Within One Year		6.3	5.1
Total Obligations Under Capital Leases		45.4	19.5
Future Minimum Lease Payments
Capital Leases, 2016		9.8
Noncancelable Operating Leases, 2016		15.6
Capital Leases, 2017		9.4
Noncancelable Operating Leases, 2017		15.2
Capital Leases, 2018		8.4
Noncancelable Operating Leases, 2018		13.8
Capital Leases, 2019		6.4
Noncancelable Operating Leases, 2019		12.4
Capital Leases, 2020		5.7
Noncancelable Operating Leases, 2020		11.8
Capital Leases, Later Years		26.5
Noncancelable Operating Leases, Later Years		36
Capital Leases, Total Future Minimum Lease Payments		66.2
Noncancelable Operating Leases, Total Future Minimum Lease Payments		104.8
Less Estimated Interest Element on Capital Leases		20.8
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		45.4
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		4.8
Indiana Michigan Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		88.3	93.4		95.6
Amortization of Capital Leases		40.7	44.4		11.3
Interest on Capital Leases		3.3	2.8		1.9
Total Lease Rental Costs		132.3	140.6		108.8
PP&E and Related Obligations Under Capital Leases
Generation		14.5	18.7
Other Property, Plant and Equipment		68.2	100.4
Total Property, Plant and Equipment Under Capital Leases		82.7	119.1
Accumulated Amortization		19.7	15.9
Net Property, Plant and Equipment Under Capital Leases		63	103.2
Noncurrent Liability		30.2	61.1
Liability Due Within One Year		32.8	42.1
Total Obligations Under Capital Leases		63	103.2
Future Minimum Lease Payments
Capital Leases, 2016		36.6
Noncancelable Operating Leases, 2016		92.7
Capital Leases, 2017		12.1
Noncancelable Operating Leases, 2017		90.9
Capital Leases, 2018		6.5
Noncancelable Operating Leases, 2018		89.7
Capital Leases, 2019		3
Noncancelable Operating Leases, 2019		88.5
Capital Leases, 2020		2.7
Noncancelable Operating Leases, 2020		85.1
Capital Leases, Later Years		20.3
Noncancelable Operating Leases, Later Years		173.8
Capital Leases, Total Future Minimum Lease Payments		81.2
Noncancelable Operating Leases, Total Future Minimum Lease Payments		620.7
Less Estimated Interest Element on Capital Leases		18.2
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		63
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.2
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,016		73.9
2,017		73.9
2,018		73.9
2,019		73.9
2,020		73.9
Later Years		147.5
Total Future Minimum Lease Payments		$ 517
Leases (Textuals) [Abstract]
Lease Term		33 years
Indiana Michigan Power Co [Member] | Nuclear Fuel Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,016		$ 26.9
2,017		5.8
2,018		2.4
Total Future Minimum Lease Payments		$ 35.1
Leases (Textuals) [Abstract]
Lease Term		54 months
Portion of Unamortized Nuclear Fuel Inventory Sold at Cost		$ 110
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 10
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 9
Ohio Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		7.6	6.6		57.8
Amortization of Capital Leases		3.9	5.7		7.8
Interest on Capital Leases		0.6	1.2		4.1
Total Lease Rental Costs		12.1	13.5		69.7
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		23.4	22.6
Total Property, Plant and Equipment Under Capital Leases		23.4	22.6
Accumulated Amortization		10.2	8
Net Property, Plant and Equipment Under Capital Leases		13.2	14.6
Noncurrent Liability		9.3	11
Liability Due Within One Year		3.9	3.6
Total Obligations Under Capital Leases		13.2	14.6
Future Minimum Lease Payments
Capital Leases, 2016		4.4
Noncancelable Operating Leases, 2016		8.8
Capital Leases, 2017		4
Noncancelable Operating Leases, 2017		8.3
Capital Leases, 2018		3.1
Noncancelable Operating Leases, 2018		6.9
Capital Leases, 2019		1
Noncancelable Operating Leases, 2019		5.4
Capital Leases, 2020		0.6
Noncancelable Operating Leases, 2020		4.5
Capital Leases, Later Years		1.4
Noncancelable Operating Leases, Later Years		20.2
Capital Leases, Total Future Minimum Lease Payments		14.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		54.1
Less Estimated Interest Element on Capital Leases		1.3
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		13.2
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		5.3
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		5.4	3.2		4.1
Amortization of Capital Leases		3.5	4.2		4.1
Interest on Capital Leases		0.7	0.7		0.8
Total Lease Rental Costs		9.6	8.1		9
PP&E and Related Obligations Under Capital Leases
Generation		9.6	9.6
Other Property, Plant and Equipment		18.6	16.5
Total Property, Plant and Equipment Under Capital Leases		28.2	26.1
Accumulated Amortization		13.6	11.8
Net Property, Plant and Equipment Under Capital Leases		14.6	14.3
Noncurrent Liability		10.9	10.9
Liability Due Within One Year		3.7	3.4
Total Obligations Under Capital Leases		14.6	14.3
Future Minimum Lease Payments
Capital Leases, 2016		4.3
Noncancelable Operating Leases, 2016		4.8
Capital Leases, 2017		4.1
Noncancelable Operating Leases, 2017		3.9
Capital Leases, 2018		2.9
Noncancelable Operating Leases, 2018		3.5
Capital Leases, 2019		1.6
Noncancelable Operating Leases, 2019		2.9
Capital Leases, 2020		1
Noncancelable Operating Leases, 2020		2.4
Capital Leases, Later Years		2.6
Noncancelable Operating Leases, Later Years		4.7
Capital Leases, Total Future Minimum Lease Payments		16.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		22.2
Less Estimated Interest Element on Capital Leases		1.9
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		14.6
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		2.8
Southwestern Electric Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		6.7	5.5		6.3
Amortization of Capital Leases		13.7	14.9		15.5
Interest on Capital Leases		6.2	7.4		8.1
Total Lease Rental Costs		26.6	27.8		$ 29.9
PP&E and Related Obligations Under Capital Leases
Generation		34.5	35.4
Other Property, Plant and Equipment		165.1	159.5
Total Property, Plant and Equipment Under Capital Leases		199.6	194.9
Accumulated Amortization		91.3	80.1
Net Property, Plant and Equipment Under Capital Leases		108.3	114.8
Noncurrent Liability		75.6	91
Liability Due Within One Year		21.9	17.6
Total Obligations Under Capital Leases		97.5	$ 108.6
Future Minimum Lease Payments
Capital Leases, 2016		26.1
Noncancelable Operating Leases, 2016		6.3
Capital Leases, 2017		18.2
Noncancelable Operating Leases, 2017		5.3
Capital Leases, 2018		12.7
Noncancelable Operating Leases, 2018		4.8
Capital Leases, 2019		11.4
Noncancelable Operating Leases, 2019		4.5
Capital Leases, 2020		9.7
Noncancelable Operating Leases, 2020		4.2
Capital Leases, Later Years		40.3
Noncancelable Operating Leases, Later Years		16.5
Capital Leases, Total Future Minimum Lease Payments		118.4
Noncancelable Operating Leases, Total Future Minimum Lease Payments		41.6
Less Estimated Interest Element on Capital Leases		20.9
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		97.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.4
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 11
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 10
Southwestern Electric Power Co [Member] | Sabine Dragline Lease [Member]
Leases (Textuals) [Abstract]
Cost of Electric Draglines to be Used for Mining Operations		$ 47
[1]	Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million, $96 million and $103 million for the Years Ended December 31, 2015, 2014 and 2013, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Amounts include Net Property Under Capital Leases that have been classified as Assets from Discontinued Operations in the amount of $179 million and Total Obligations Under Capital Leases that have been classified as Liabilities from Discontinued Operations in the amount of $189 million on the December 31, 2014 balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[3]	AEP’s future minimum lease payments includes equal shares from AEGCo and I&M.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Thousands		1 Months Ended		12 Months Ended
		Feb. 23, 2016	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Shares of Company
Beginning Balance, Shares			511,389,173	509,739,159	508,113,964		506,004,962
Issued				1,650,014	1,625,195		2,109,002
Treasury Stock, Shares, Ending Balance				20,336,592	20,336,592		20,336,592
Ending Balance, Shares				511,389,173	509,739,159		508,113,964
Long-term Debt
Senior Unsecured Notes				$ 13,629,100	$ 12,562,100
Pollution Control Bonds	[1]			1,784,800	1,951,800
Notes Payable - Affiliated				0	0
Notes Payable	[2]			264,700	274,100	[3]
Securitization Bonds				2,024,000	2,360,900
Spent Nuclear Fuel Obligation	[4]			265,600	265,500
Other Long-term Debt				1,604,500	1,098,000
Total Long-term Debt Outstanding				19,572,700	18,512,400	[3],[5]
Outstanding Long-term Debt
Principal Amount, 2016				1,831,800
Principal Amount, 2017				2,689,600
Principal Amount, 2018				1,726,900
Principal Amount, 2019				1,813,200
Principal Amount, 2020				368,200
Principal Amount, After 2020				11,262,400
Principal Amount, Total				19,692,100
Unamortized Discount, Net and Debt Issuance Costs				(119,400)
Total Long-term Debt Outstanding				19,572,700	18,512,400	[3],[5]
Short-term Debt
Securitized Debt for Receivables	[6]			675,000	744,000
Commercial Paper				125,000	602,000
Total Short-term Debt				$ 800,000	$ 1,346,000
Securitized Debt for Receivables	[7]			0.30%	0.22%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable				0.30%	0.22%		0.23%
Net Uncollectible Accounts Receivable Written Off				$ 34,100	$ 40,100		$ 34,900
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts				924,800	974,500
Total Principal Outstanding				675,000	744,000
Delinquent Securitized Accounts Receivable				48,300	43,900
Bad Debt Reserves Related to Securitized Sale of Accounts Receivable				17,500	12,900
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable				357,800	335,400
Financing Activities (Textuals) [Abstract]
Disposal Group, Including Discontinued Operation, Long-term Debt					83,200
Repayments of Long-term Debt				2,397,900	1,777,400		2,595,400
Issuance of Long-term Debt				3,436,600	2,067,000		3,206,600
Total Commitment From Bank Conduits To Finance Receivables				750,000	$ 700,000
Reaquired Pollution Control Bonds Held by Trustees				554,000
Credit Facilities, Total				$ 3,500,000
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 8,100,000
Maximum Amount of Commercial Paper Outstanding				$ 788,000
Weighted Average Interest Rate of Commercial Paper Outstanding During Year				0.46%
Commercial Paper [Member]
Short-term Debt
Commercial Paper	[7]			0.81%	0.59%
Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,045
Weighted Average Interest Rate				5.09%
Interest Rate Ranges, Minimum				1.65%	1.65%
Interest Rate Ranges, Maximum				8.13%	8.13%
Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[8]			2,015
Maturity Date High	[8]			2,038
Weighted Average Interest Rate				2.71%
Interest Rate Ranges, Minimum				0.01%	0.04%
Interest Rate Ranges, Maximum				6.30%	6.30%
Notes Payable [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,032
Weighted Average Interest Rate				2.47%
Interest Rate Ranges, Minimum				0.925%	0.983%
Interest Rate Ranges, Maximum				6.60%	8.03%
Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,031
Weighted Average Interest Rate				3.66%
Interest Rate Ranges, Minimum				0.88%	0.88%
Interest Rate Ranges, Maximum				6.25%	6.25%
Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,059
Weighted Average Interest Rate				1.62%
Interest Rate Ranges, Minimum				1.15%	1.15%
Interest Rate Ranges, Maximum				13.718%	13.718%
Appalachian Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,970,400	$ 2,976,100
Pollution Control Bonds	[1]			616,500	530,600
Notes Payable - Affiliated				0	86,000
Securitization Bonds				341,500	363,700
Other Long-term Debt				2,300	2,300
Total Long-term Debt Outstanding				3,930,700	3,958,700
Outstanding Long-term Debt
Principal Amount, 2016				318,000
Principal Amount, 2017				273,500
Principal Amount, 2018				124,000
Principal Amount, 2019				180,400
Principal Amount, 2020				24,900
Principal Amount, After 2020				3,045,000
Principal Amount, Total				3,965,800
Unamortized Discount, Net and Debt Issuance Costs				(35,100)
Total Long-term Debt Outstanding				3,930,700	3,958,700
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				135,400	159,800
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				7,600	8,900		6,500
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,453,800	1,519,300		1,443,000
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				672,600	612,700		345,000
Issuance of Long-term Debt				$ 726,300	394,200		$ 444,400
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 0
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				211,200	44,200
Maximum Loans to Money Pool				694,800	542,200
Average Borrowings from Money Pool				82,000	12,600
Average Loans to Money Pool				79,000	104,500
Net Loans (Borrowings) to/from Money Pool				(155,400)	48,500
Authorized Short Term Borrowing Limit				$ 600,000	$ 600,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%	0.59%		0.43%
Minimum Interest Rate				0.37%	0.24%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.53%	0.29%		0.33%
Average Interest Rate For Funds Loaned				0.47%	0.29%		0.33%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 200	$ 0		$ 400
Interest Income
Interest Income Earned On Advances To Money Pool				$ 400	$ 300		100
Appalachian Power Co [Member] | Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,045
Weighted Average Interest Rate				5.39%
Interest Rate Ranges, Minimum				3.40%	3.40%
Interest Rate Ranges, Maximum				7.00%	7.95%
Appalachian Power Co [Member] | Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[8]			2,015
Maturity Date High	[8]			2,038
Weighted Average Interest Rate				1.70%
Interest Rate Ranges, Minimum				0.01%	0.04%
Interest Rate Ranges, Maximum				5.375%	5.375%
Appalachian Power Co [Member] | Pollution Control Bonds [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 75,000
Issuance of Long-term Debt			$ 75,000
Due Date			2,016
Appalachian Power Co [Member] | Notes Payable Affiliated [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,015
Weighted Average Interest Rate
Interest Rate Ranges, Minimum					3.125%
Interest Rate Ranges, Maximum					3.125%
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,024
Maturity Date High				2,031
Weighted Average Interest Rate				2.85%
Interest Rate Ranges, Minimum				2.008%	2.008%
Interest Rate Ranges, Maximum				3.772%	3.772%
Appalachian Power Co [Member] | Securitization Bonds [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 11,000
Appalachian Power Co [Member] | Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,026
Maturity Date High				2,026
Weighted Average Interest Rate				13.718%
Interest Rate Ranges, Minimum				13.718%	13.718%
Interest Rate Ranges, Maximum				13.718%	13.718%
Indiana Michigan Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,117,000	$ 1,240,800
Pollution Control Bonds	[1]			225,100	224,800
Notes Payable	[2]			175,500	176,700
Spent Nuclear Fuel Obligation	[4]			265,600	265,500
Other Long-term Debt				216,800	111,800
Total Long-term Debt Outstanding				2,000,000	2,019,600
Outstanding Long-term Debt
Principal Amount, 2016				162,900
Principal Amount, 2017				68,500
Principal Amount, 2018				318,000
Principal Amount, 2019				484,100
Principal Amount, 2020				1,800
Principal Amount, After 2020				975,100
Principal Amount, Total				2,010,400
Unamortized Discount, Net and Debt Issuance Costs				(10,400)
Total Long-term Debt Outstanding				2,000,000	2,019,600
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				134,800	137,500
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				8,400	7,900		6,500
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,553,000	1,488,600		1,458,800
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				332,100	218,500		370,300
Issuance of Long-term Debt				310,700	205,600		$ 348,900
Reaquired Pollution Control Bonds Held by Trustees				$ 40,000
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 92,000
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				297,300	150,700
Maximum Loans to Money Pool				13,500	158,900
Average Borrowings from Money Pool				152,600	73,200
Average Loans to Money Pool				13,500	39,100
Net Loans (Borrowings) to/from Money Pool				(282,600)	(129,000)
Authorized Short Term Borrowing Limit				$ 500,000	$ 500,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%	0.59%		0.43%
Minimum Interest Rate				0.37%	0.24%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.49%	0.31%		0.36%
Average Interest Rate For Funds Loaned				0.48%	0.30%		0.32%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 800	$ 100		$ 100
Interest Income
Interest Income Earned On Advances To Money Pool				$ 100	$ 100		900
Indiana Michigan Power Co [Member] | Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,037
Weighted Average Interest Rate				5.82%
Interest Rate Ranges, Minimum				3.20%	3.20%
Interest Rate Ranges, Maximum				7.00%	7.00%
Indiana Michigan Power Co [Member] | Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[8]			2,015
Maturity Date High	[8]			2,025
Weighted Average Interest Rate				1.79%
Interest Rate Ranges, Minimum				0.01%	0.04%
Interest Rate Ranges, Maximum				4.625%	4.625%
Indiana Michigan Power Co [Member] | Notes Payable [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,019
Weighted Average Interest Rate				1.02%
Interest Rate Ranges, Minimum				0.925%	0.983%
Interest Rate Ranges, Maximum				2.12%	2.12%
Indiana Michigan Power Co [Member] | Notes Payable [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		8,000	$ 14,000
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,025
Weighted Average Interest Rate				2.14%
Interest Rate Ranges, Minimum				1.81%	1.55%
Interest Rate Ranges, Maximum				6.00%	6.00%
Ohio Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,938,900	$ 1,937,300
Pollution Control Bonds	[1]			32,200	118,200
Securitization Bonds				185,300	229,900
Other Long-term Debt				1,300	1,400
Total Long-term Debt Outstanding				2,157,700	2,286,800
Outstanding Long-term Debt
Principal Amount, 2016				395,900
Principal Amount, 2017				46,400
Principal Amount, 2018				397,000
Principal Amount, 2019				48,000
Principal Amount, 2020				100
Principal Amount, After 2020				1,283,100
Principal Amount, Total				2,170,500
Unamortized Discount, Net and Debt Issuance Costs				(12,800)
Total Long-term Debt Outstanding				2,157,700	2,286,800
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				351,400	365,800
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				30,700	28,800		21,600
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				2,569,400	2,647,600		2,620,500
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				131,500	438,600		1,196,000
Issuance of Long-term Debt				0	0		$ 1,378,300
Reaquired Pollution Control Bonds Held by Trustees				345,000
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				0	120,300
Maximum Loans to Money Pool				367,500	405,400
Average Borrowings from Money Pool				0	34,800
Average Loans to Money Pool				266,600	107,300
Net Loans (Borrowings) to/from Money Pool				331,100	312,500
Authorized Short Term Borrowing Limit				$ 400,000	$ 400,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%	0.59%		0.43%
Minimum Interest Rate				0.37%	0.24%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.00%	0.27%		0.33%
Average Interest Rate For Funds Loaned				0.48%	0.34%		0.32%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 0	$ 0		$ 500
Interest Income
Interest Income Earned On Advances To Money Pool				$ 1,300	$ 200		200
Ohio Power Co [Member] | Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,035
Weighted Average Interest Rate				5.98%
Interest Rate Ranges, Minimum				5.375%	5.375%
Interest Rate Ranges, Maximum				6.60%	6.60%
Ohio Power Co [Member] | Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[8]			2,015
Maturity Date High	[8]			2,038
Weighted Average Interest Rate				5.80%
Interest Rate Ranges, Minimum				5.80%	3.125%
Interest Rate Ranges, Maximum				5.80%	5.80%
Ohio Power Co [Member] | Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,020
Weighted Average Interest Rate				1.56%
Interest Rate Ranges, Minimum				0.958%	0.958%
Interest Rate Ranges, Maximum				2.049%	2.049%
Ohio Power Co [Member] | Securitization Bonds [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 23,000
Ohio Power Co [Member] | Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,028
Maturity Date High				2,028
Weighted Average Interest Rate				1.15%
Interest Rate Ranges, Minimum				1.15%	1.15%
Interest Rate Ranges, Maximum				1.15%	1.15%
Public Service Co Of Oklahoma [Member]
Shares of Company
Beginning Balance, Shares			10,482,000	10,482,000
Ending Balance, Shares				10,482,000	10,482,000
Long-term Debt
Senior Unsecured Notes				$ 1,142,700	$ 893,000
Pollution Control Bonds	[1]			12,600	12,600
Other Long-term Debt				130,800	131,100
Total Long-term Debt Outstanding				1,286,100	1,036,700
Outstanding Long-term Debt
Principal Amount, 2016				275,400
Principal Amount, 2017				500
Principal Amount, 2018				500
Principal Amount, 2019				250,500
Principal Amount, 2020				13,100
Principal Amount, After 2020				753,500
Principal Amount, Total				1,293,500
Unamortized Discount, Net and Debt Issuance Costs				(7,400)
Total Long-term Debt Outstanding				1,286,100	1,036,700
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				116,100	112,900
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				5,800	5,900		5,600
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,326,100	1,321,100		1,232,400
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				400	34,100		400
Issuance of Long-term Debt				$ 248,800	75,000		$ 49,700
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 105,000
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				165,900	177,000
Maximum Loans to Money Pool				152,500	0
Average Borrowings from Money Pool				113,100	93,700
Average Loans to Money Pool				86,800	0
Net Loans (Borrowings) to/from Money Pool				80,600	(154,200)
Authorized Short Term Borrowing Limit				$ 300,000	$ 300,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%	0.59%		0.43%
Minimum Interest Rate				0.37%	0.24%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.49%	0.29%		0.34%
Average Interest Rate For Funds Loaned				0.48%	0.00%		0.33%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 100	$ 300		$ 0
Interest Income
Interest Income Earned On Advances To Money Pool				$ 400	$ 0		100
Public Service Co Of Oklahoma [Member] | Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,045
Weighted Average Interest Rate				5.11%
Interest Rate Ranges, Minimum				3.17%	4.40%
Interest Rate Ranges, Maximum				6.625%	6.625%
Public Service Co Of Oklahoma [Member] | Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,020
Maturity Date High				2,020
Weighted Average Interest Rate				4.45%
Interest Rate Ranges, Minimum				4.45%	4.45%
Interest Rate Ranges, Maximum				4.45%	4.45%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,027
Weighted Average Interest Rate				1.80%
Interest Rate Ranges, Minimum				1.587%	1.482%
Interest Rate Ranges, Maximum				3.00%	3.00%
Southwestern Electric Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 1,961,000	$ 1,816,900
Pollution Control Bonds	[1]			134,500	134,400
Notes Payable	[2]			78,600	81,900
Other Long-term Debt				99,400	99,200
Total Long-term Debt Outstanding				2,273,500	2,132,400
Outstanding Long-term Debt
Principal Amount, 2016				3,300
Principal Amount, 2017				353,300
Principal Amount, 2018				384,900
Principal Amount, 2019				456,700
Principal Amount, 2020				3,300
Principal Amount, After 2020				1,087,400
Principal Amount, Total				2,288,900
Unamortized Discount, Net and Debt Issuance Costs				(15,400)
Total Long-term Debt Outstanding				2,273,500	2,132,400
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				151,800	148,700
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				7,000	6,800		5,900
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,597,800	1,655,800		1,533,800
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				306,800	3,300		3,300
Issuance of Long-term Debt				$ 445,900	99,400		$ 0
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 354,000
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				112,500	153,500
Maximum Loans to Money Pool				299,900	51,300
Average Borrowings from Money Pool				48,100	71,000
Average Loans to Money Pool				103,400	24,400
Net Loans (Borrowings) to/from Money Pool				(58,300)	41,000
Authorized Short Term Borrowing Limit				$ 350,000	$ 350,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%	0.59%		0.43%
Minimum Interest Rate				0.37%	0.24%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.53%	0.29%		0.34%
Average Interest Rate For Funds Loaned				0.48%	0.32%		0.36%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 100	$ 200		$ 0
Interest Income
Interest Income Earned On Advances To Money Pool				400	$ 0		$ 100
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool				2,000
Average Loans to Money Pool				2,000
Net Loans (Borrowings) to/from Money Pool				$ 2,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				0.87%
Minimum Interest Rate				0.37%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Loaned				0.48%
Interest Income
Interest Income Earned On Advances To Money Pool				$ 4
Southwestern Electric Power Co [Member] | Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,015
Maturity Date High				2,045
Weighted Average Interest Rate				5.28%
Interest Rate Ranges, Minimum				3.55%	3.55%
Interest Rate Ranges, Maximum				6.45%	6.45%
Southwestern Electric Power Co [Member] | Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[8]			2,015
Maturity Date High	[8]			2,019
Weighted Average Interest Rate				3.62%
Interest Rate Ranges, Minimum				1.60%	3.25%
Interest Rate Ranges, Maximum				4.95%	4.95%
Southwestern Electric Power Co [Member] | Notes Payable [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,024
Maturity Date High				2,032
Weighted Average Interest Rate				5.15%
Interest Rate Ranges, Minimum				4.58%	4.58%
Interest Rate Ranges, Maximum				6.37%	6.37%
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,017
Weighted Average Interest Rate				1.82%
Interest Rate Ranges, Minimum				1.82%	1.73%
Interest Rate Ranges, Maximum				1.82%	1.73%
AEP Texas Central Co [Member] | Securitization Bonds [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 128,000
Transource Missouri [Member] | Other Long Term Debt [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt		3,000
Credit Facility		$ 300,000
Due Date		2,018
[1]	For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series.
[2]	Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
[3]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[4]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[5]	Amount excludes $83 million of Long-term Debt classified as Liabilities from Discontinued Operations on the balance sheet. See "AEPRO (Corporate and Other)" section of Note 7 for additional information.
[6]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[7]	Weighted average rate.
[8]	Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Based Compensation (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		10,000,000
Number of Shares Remaining Available for Issuance Under the AEP Long-Term Incentive Plan		9,964,153
Reduction in Aggregate Common Shares Authorized Per Share Issued Pursuant to Stock Options or Stock Appreciation Rights		0.286
Employee Stock Option [Member]
Total Fair Value of Stock Options Vested and Total Intrinsic Value of Options Exercised
Intrinsic Value of Options Exercised	[1]	$ 0	$ 0	$ 3.1
Summary of Stock Option Transactions
Options, Outstanding, Beginning Balance		0	0	188,500
Weighted Average Exercise Price, Outstanding, Beginning Balance				$ 30.17
Options, Granted		0	0	0
Options, Exercised/Converted		0	0	(187,500)
Weighted Average Exercise Price, Exercised/Converted				$ 30.18
Options, Forfeited/Expired		0	0	(1,000)
Weighted Average Exercise Price, Forfeited/Expired				$ 27.95
Options, Outstanding, Ending Balance		0	0	0
Options Exercisable		0	0	0
Stock Based Compensation (Textuals) [Abstract]
Maximum Contractual Term for Stock Options (in years)		10 years
Performance Units [Member]
Performance Units
Awarded Units		575,000	16,900	1,284,200
Weighted Average Grant Date Fair Value, Granted		$ 59.19	$ 49.73	$ 46.23
Vesting Period (in years)		3 years	3 years	3 years
Certified Performance Scores and Units Earned
Certified Performance Score		176.30%	147.80%	118.80%
Performance Units Earned		1,202,107	889,697	749,219
Performance Units Manditorily Deferred as AEP Career Shares		41,707	40,831	72,883
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program		54,074	39,526	39,691
Performance Units to be Paid in Cash		1,106,326	809,340	636,645
Cash Payouts
Cash Payouts for Performance Units		$ 48.1	$ 29.3	$ 43.9
Cash Payouts for AEP Career Share Distributions		$ 3	$ 4.3	$ 3.7
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 59.19	$ 49.73	$ 46.23
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		59.19	49.73	46.23
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 59.19	$ 49.73	$ 46.23
Stock Based Compensation (Textuals) [Abstract]
Performance Score by HR Committee, Lower Range		0.00%
Performance Score by HR Committee, Higher Range		200.00%
Restricted Stock Units (RSUs) [Member]
Stock Based Compensation (Textuals) [Abstract]
Maximum Contractual Term of Outstanding Restricted Stock Units (in months)		40 months
Performance Units and AEP Career Shares Reinvested Dividends Portion For [Member]
Performance Units
Awarded Units		103,600	98,900	100,900
Weighted Average Grant Date Fair Value, Granted		$ 54.35	$ 53.35	$ 45.42
Vesting Period	[2]	(a)	(a)	(a)
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 54.35	$ 53.35	$ 45.42
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		54.35	53.35	45.42
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 54.35	$ 53.35	$ 45.42
Restricted Shares and Restricted Stock Units [Member]
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested
Fair Value of Restricted Shares and Restricted Stock Units Vested		$ 18.3	$ 18.7	$ 15.3
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	[3]	$ 24.2	$ 24.9	$ 20.4
Restricted Stock [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 58.56	$ 50.36	$ 46.24
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		397,500	64,100	644,400
Weighted Average Grant Date Fair Value		$ 58.56	$ 50.36	$ 46.24
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		783,000
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 44.59
Shares/Units, Granted		397,500	64,100	644,400
Weighted Average Grant Date Fair Value, Granted		$ 58.56	$ 50.36	$ 46.24
Shares/Units, Vested		(425,400)
Weighted Average Grant Date Fair Value, Vested		$ 42.94
Shares/Units, Forfeited		(33,800)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 51.07
Nonvested, Shares/Units, Ending Balance		721,300	783,000
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 52.48	$ 44.59
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		397,500	64,100	644,400
Weighted Average Grant Date Fair Value		$ 58.56	$ 50.36	$ 46.24
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		397,500	64,100	644,400
Shares/Units, Vested		(425,400)
Total Aggregate Intrinsic Value of Nonvested Shares		$ 41
Weighted Average Remaining Contractual Life of Nonvested Shares (in years)		1.9 years
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 55.46	$ 54.08	$ 45.81
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		24,900	25,400	32,700
Weighted Average Grant Date Fair Value		$ 55.46	$ 54.08	$ 45.81
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		24,900	25,400	32,700
Weighted Average Grant Date Fair Value, Granted		$ 55.46	$ 54.08	$ 45.81
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		24,900	25,400	32,700
Weighted Average Grant Date Fair Value		$ 55.46	$ 54.08	$ 45.81
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		24,900	25,400	32,700
Number of Years After Termination of Board Service Participant Can Elect to Have Stock Units Paid in Cash		10 years
Cash Payouts for Stock Unit Accumulation Plan		$ 1	$ 5	$ 2
Stock Based Compensation [Member]
Compensation Cost and Actual Tax Benefit Realized for the Tax Deductions from Compensation Cost for Share-based Payment Arrangements
Compensation Cost for Share-based Payment Arrangements	[4]	63.8	85.4	56.4
Actual Tax Benefit Realized		22.3	29.9	19.7
Total Compensation Cost Capitalized		20.3	23.1	13.2
Cash Received from Stock Options Exercised and Actual Tax Benefit Realized for Tax Deductions from Stock Options Exercised
Cash Received from Stock Options Exercised		0	0	5.7
Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised		0	$ 0	$ 1
Stock Based Compensation (Textuals) [Abstract]
Total Unrecognized Compensation Cost Related to Unvested Share-based Compensation Arrangements Granted		$ 72
Weighted-average Period of Unrecognized Compensation Costs (in years)		1.4 years
Granted 2010 [Member] | Restricted Stock [Member] | Granted to Previous Chief Executive Officer Succession Candidates [Member] | August 3, 2013 through August 3, 2015 [Member]
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		165,520
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		165,520
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		165,520
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		165,520
[1]	Intrinsic value is calculated as market price at exercise dates less the option exercise price.
[2]	The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s employment ends.
[3]	Intrinsic value is calculated as market price at exercise date.
[4]	Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)plantMW	Dec. 31, 2014USD ($)		Dec. 31, 2013USD ($)
Related Party Transactions (Textuals) [Abstract]
Aggregate Power Participation Ratio		43.47%
Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		43.47%
Investment		$ 4,400
Ohio Valley Electric Corporation [Member] | Environmental Project [Member]
Related Party Transactions (Textuals) [Abstract]
Authorized Capital Expenditures for Environmental Investments		1,300,000
Appalachian Power Co to Indiana Michigan Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		0	$ 300
Appalachian Power Co to Public Service Co of Oklahoma [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		0	100
Appalachian Power Co to Southwestern Electric Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		0	100
Indiana Michigan Power Co to Appalachian Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		$ 0
Indiana Michigan Power Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals) [Abstract]
Percentage of Power Sold under Unit Power Agreement		30.00%
Indiana Michigan Power Co to Public Service Co of Oklahoma [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		$ 600	1,300
Indiana Michigan Power Co to Southwestern Electric Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		1,800	2,200
Ohio Power Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services	[1]				$ 15,600
Railcar Maintenance	[2]				1,300
Ohio Power Co to Public Service Co of Oklahoma [Member]
Cook Coal Terminal
Railcar Maintenance					100
Ohio Power Co to Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance					1,200
Public Service Co of Oklahoma to Appalachian Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		300
Public Service Co of Oklahoma to Indiana Michigan Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		400	100
Public Service Co of Oklahoma to Southwestern Electric Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		600	200
Southwestern Electric Power Co to Appalachian Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		300
Southwestern Electric Power Co to Indiana Michigan Power Co [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		1,200	1,100
Southwestern Electric Power Co to Public Service Co of Oklahoma [Member]
Affiliate Railcar Agreement [Abstract]
Revenue Related to Affiliate Railcar Agreement		600	700
AEP Generating Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services		15,800	16,200		6,800
Railcar Maintenance		$ 2,000	2,500		1,100
AEP Generating Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals) [Abstract]
Percentage of Power Sold under Unit Power Agreement		30.00%
AEP Generating Co to Ohio Power Co [Member]
Cook Coal Terminal
Coal Transloading Services		$ 0	0		300
AEP Generating Co to Public Service Co of Oklahoma [Member]
Cook Coal Terminal
Railcar Maintenance		200	300		100
AEP Generating Co To Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance		2,800	3,300		1,200
Appalachian Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		147,800	144,500		347,500
Cost of Purchased Power from Affiliate		0	4,700		830,900
Transmission Agreement
Net Charges from Transmission Agreement		92,700	84,700		40,600
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		37,700	36,100		30,900
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		87,200	96,900		104,400
Sales and Purchases of Property [Abstract]
Related Party Sales of Property		9,400	3,000		3,200
Related Party Purchases of Property		$ 8,600	900		5,200
Related Party Transactions (Textuals) [Abstract]
Aggregate Power Participation Ratio		43.47%
Appalachian Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			4,700	[3]	830,900
Appalachian Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Appalachian Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Appalachian Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		$ 0	0
Appalachian Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Appalachian Power Co [Member] | Auction Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Appalachian Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Appalachian Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Appalachian Power Co [Member] | Natural Gas Purchases from AEPES [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Appalachian Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			200	[3]	193,700
Appalachian Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		132,100	141,700		129,000
Appalachian Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			600		600
Appalachian Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[4]	10,600
Appalachian Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Appalachian Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		700	(1,600)		400
Appalachian Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4,400	3,600		23,800
Indiana Michigan Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		27,400	4,200		219,400
Cost of Purchased Power from Affiliate		232,100	270,000		433,200
Transmission Agreement
Net Charges from Transmission Agreement		38,000	39,700		19,900
Central Machine Shop
Billings for Services from Central Machine Shop Facility		2,500	1,700		2,500
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		43,700	48,500		52,200
Sales and Purchases of Property [Abstract]
Related Party Sales of Property		3,000	1,300		5,000
Related Party Purchases of Property		8,100	1,400		1,000
Related Party Transactions (Textuals) [Abstract]
Barge Towing and Chartering Services		$ 19,000	24,000		24,000
Aggregate Power Participation Ratio		43.47%
Indiana Michigan Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			1,600	[3]	181,700
Indiana Michigan Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Indiana Michigan Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Indiana Michigan Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		$ 0	0
Indiana Michigan Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Indiana Michigan Power Co [Member] | Auction Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Indiana Michigan Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Indiana Michigan Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		232,100	268,400		251,500
Indiana Michigan Power Co [Member] | Natural Gas Purchases from AEPES [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Indiana Michigan Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			500	[3]	218,200
Indiana Michigan Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Indiana Michigan Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			400		400
Indiana Michigan Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[4]	17,100
Indiana Michigan Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Indiana Michigan Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		8,400	1,700		(700)
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1,900	1,600		1,500
Kentucky Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		4,600	5,000		100
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1,300	1,200		700
Ohio Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		84,100	165,200		1,166,900
Cost of Purchased Power from Affiliate		496,400	1,192,700		349,700
Transmission Agreement
Net Charges from Transmission Agreement		81,000	17,000		8,900
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		0	0		40,600
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0	0		4,700
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		110,800	123,100		132,600
Sales and Purchases of Property [Abstract]
Related Party Sales of Property		2,400	500		59,800
Related Party Purchases of Property		$ 2,100	1,900		5,300
Related Party Transactions (Textuals) [Abstract]
Aggregate Power Participation Ratio		43.47%
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		4.30%
Investment		$ 400
Ohio Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			100	[3]	199,300
Ohio Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Ohio Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Ohio Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		238,500	1,148,200
Ohio Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			44,400
Ohio Power Co [Member] | Auction Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	225,200
Ohio Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	32,700
Ohio Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		148,400
Ohio Power Co [Member] | Natural Gas Purchases from AEPES [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					2,000
Ohio Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			1,100	[3]	924,300
Ohio Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		152,700
Ohio Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			0		800
Ohio Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[4]	0
Ohio Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		29,700	44,100		0
Ohio Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		35,500	104,100		53,400
Ohio Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		18,900	15,900		35,700
Public Service Co Of Oklahoma [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4,600	7,100		14,200
Cost of Purchased Power from Affiliate		0	11,000		36,900
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		15,000	14,100		14,700
Central Machine Shop
Billings for Services from Central Machine Shop Facility		200	300		600
Sales and Purchases of Property [Abstract]
Related Party Sales of Property		7,100	500		5,700
Related Party Purchases of Property		600	2,100		1,700
Public Service Co Of Oklahoma [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0	[3]	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			1,000		1,500
Public Service Co Of Oklahoma [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			10,000		35,400
Public Service Co Of Oklahoma [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Public Service Co Of Oklahoma [Member] | Auction Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Public Service Co Of Oklahoma [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Public Service Co Of Oklahoma [Member] | Natural Gas Purchases from AEPES [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Public Service Co Of Oklahoma [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			0	[3]	0
Public Service Co Of Oklahoma [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	3,800		0
Public Service Co Of Oklahoma [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			0		10,800
Public Service Co Of Oklahoma [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[4]	0
Public Service Co Of Oklahoma [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Public Service Co Of Oklahoma [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		200	0		0
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4,400	3,300		3,400
Southwestern Electric Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		16,600	26,300		51,800
Cost of Purchased Power from Affiliate		0	3,800		11,200
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		(15,000)	(14,100)		(14,700)
Central Machine Shop
Billings for Services from Central Machine Shop Facility		800	100		200
Sales and Purchases of Property [Abstract]
Related Party Sales of Property		800	1,200		1,600
Related Party Purchases of Property		7,400	4,000		8,400
Southwestern Electric Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0	[3]	0
Southwestern Electric Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		400
Southwestern Electric Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			3,800		10,800
Southwestern Electric Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0
Southwestern Electric Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0
Southwestern Electric Power Co [Member] | Auction Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Southwestern Electric Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[4]	0
Southwestern Electric Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Southwestern Electric Power Co [Member] | Natural Gas Purchases from AEPES [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Southwestern Electric Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			0	[3]	0
Southwestern Electric Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	10,100		0
Southwestern Electric Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues			300		35,400
Southwestern Electric Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[4]	0
Southwestern Electric Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(200)	0		(100)
Southwestern Electric Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		15,200	14,100		14,700
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1,600	1,800		1,800
AEP Generating Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		16,100	22,700		19,700
Central Machine Shop
Billings for Services from Central Machine Shop Facility		100	100		0
AEP River Operations LLC [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		$ 15,500	25,300		22,600
American Electric Power [Member] | Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		39.17%
Investment		$ 4,000
AEP Subsidiaries [Member]
Related Party Transactions (Textuals) [Abstract]
Aggregate Power Participation Ratio		43.47%
Ohio Valley Electric Corporation [Member]
Related Party Transactions (Textuals) [Abstract]
Approximate OVEC Generating Capacity (In MWs) | MW		2,400
Number of OVEC Generating Plants | plant		2
Number of Plants Operating with Environmental Controls | plant		2
Ohio Valley Electric Corporation [Member] | Environmental Project [Member]
Related Party Transactions (Textuals) [Abstract]
Authorized Capital Expenditures for Environmental Investments		$ 1,300,000
AEP Generation Resources [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		4,900	5,200		0
Central Machine Shop
Billings for Services from Central Machine Shop Facility		$ 2,700	2,800		$ 0
Rockport Plant CCT Project [Member] | Ohio Power Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services			7,000
Railcar Maintenance			$ 608
[1]	Includes $7 million in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
[2]	Includes $608 thousand in 2013 of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013.
[3]	Includes December 2013 true-up activity subsequent to agreement termination.
[4]	Refer to the Ohio Auctions section below for further information regarding these amounts.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	$ 2,024		$ 2,360.9
Securitized Transition Assets	$ 1,749.9		2,072.4
Percentage Ownership of "Allegheny Series" by a Nonaffiliated Company	100.00%
Protected Cell Of Energy Insurance Services, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Insurance Premium Expense to Protected Cell	$ 29		32		$ 31
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Assets [Member]
ASSETS
Assets	165.3		149
Protected Cell Of Energy Insurance Services, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Protected Cell Of Energy Insurance Services, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	1.9		1.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	167.2		150.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	41.8		44.3
Protected Cell Of Energy Insurance Services, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	83.9		61.4
Protected Cell Of Energy Insurance Services, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	41.5		45.2
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	167.2		150.9
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution	47		23
Transource Energy [Member] | Current Assets [Member]
ASSETS
Assets	10.8		2.4
Transource Energy [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	227.2		98
Transource Energy [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	5.5		3.7
Transource Energy [Member] | Total Assets [Member]
ASSETS
Assets	243.5		104.1
Transource Energy [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	36.6		20.8
Transource Energy [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	113		54.7
Transource Energy [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	93.9		28.6
Transource Energy [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 243.5		104.1
AEP Credit, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Minimum Percentage of Equity AEP Provides	5.00%
Percentage Of Short Term Borrowing Needs In Excess Of Third Party Financings	20.00%
AEP Credit, Inc. [Member] | Current Assets [Member]
ASSETS
Assets	$ 925.7		979.9
AEP Credit, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
AEP Credit, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	6.4		0.5
AEP Credit, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	932.1		980.4
AEP Credit, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	855.1		894.5
AEP Credit, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.3		0.3
AEP Credit, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	76.7		85.6
AEP Credit, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	932.1		980.4
PATH West Virginia Transmission Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	18.8		18.8
Maximum Exposure	18.8		18.8
PATH West Virginia Transmission Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	2.2		2.2
Maximum Exposure	2.2		2.2
PATH West Virginia Transmission Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	21		21
Maximum Exposure	21		21
AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	1,500		1,800
Securitized Transition Assets	1,300		1,600
AEP Texas Central Transition Funding Co [Member] | Current Assets [Member]
ASSETS
Assets	234.1		238.5
AEP Texas Central Transition Funding Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
AEP Texas Central Transition Funding Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	1,365.7	[1]	1,641.5	[2]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	68		75
AEP Texas Central Transition Funding Co [Member] | Total Assets [Member]
ASSETS
Assets	1,599.8		1,880
AEP Texas Central Transition Funding Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	291.7		321.5
AEP Texas Central Transition Funding Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1,290		1,540.4
AEP Texas Central Transition Funding Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	18.1		18.1
AEP Texas Central Transition Funding Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 1,599.8		1,880
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	13.50%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of VIE Sales of Lignite Produced	50.00%
Appalachian Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	$ 341.5		363.7
Securitized Transition Assets	328		350.2
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	227.5		216.5		174.4
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	25.8		30.7
Maximum Exposure	25.8		30.7
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	342		364
Securitized Transition Assets	328		350
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Assets [Member]
ASSETS
Assets	18.5		18.1
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	332	[3]	354.4	[4]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	4		4
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Assets [Member]
ASSETS
Assets	350.5		372.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	27.1		26.8
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	321.5		343.8
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.9		1.9
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	350.5		372.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals) [Abstract]
Payments Made by I&M to DCC Fuel	115		109		153
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Assets [Member]
ASSETS
Assets	91.1		97.4
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	159.9		158.1
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	84.6		79.7
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Assets [Member]
ASSETS
Assets	335.6		335.2
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	84.8		86
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	250.8		249.2
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0		0
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	335.6		335.2
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	139.5		133.2		119.3
Indiana Michigan Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	232		268		252
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	16.6		22.5
Maximum Exposure	16.6		22.5
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Generating Company's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	17		20
Ohio Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	185.3		229.9
Securitized Transition Assets	85.9		110
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	177.8		169		255.5
Ohio Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE					148
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	23.3		24.7
Maximum Exposure	23.3		24.7
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	185		230
Securitized Transition Assets	86		110
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Assets [Member]
ASSETS
Assets	31.2		32.7
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	162	[5]	207.3	[6]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	76		97
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Assets [Member]
ASSETS
Assets	193.2		240
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	47.3		47.1
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	144.6		191.6
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.3		1.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	193.2		240
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	107.3		101.4		86
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	12.6		15.3
Maximum Exposure	12.6		15.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	152		151		155
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Assets [Member]
ASSETS
Assets	61.7		68
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	147		145.5
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	61.8		51.1
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Assets [Member]
ASSETS
Assets	270.5		264.6
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	47.7		36.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	222.3		227.9
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.5		0.4
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	270.5		264.6
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	$ 93		56		60
Percentage of VIE Sales of Lignite Produced	50.00%
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO	50.00%
Percentage of Management Fee Received by SWEPCo from DHLC	100.00%
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	$ 7.6		7.6
Maximum Exposure	7.6		7.6
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	7.7		3.8
Maximum Exposure	7.7		3.8
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Advance Due to Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	0		56
Maximum Exposure	0		56
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | SWEPCo's Guarantee Of Debt [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	0		0
Maximum Exposure	82.9		48.3
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	15.3		67.4
Maximum Exposure	98.2		115.7
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	141.4		140.3		$ 125.4
Southwestern Electric Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	16.4		20.8
Maximum Exposure	$ 16.4		$ 20.8
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage Interest in Rockport Plant Unit 2 Lease	50.00%
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	100.00%
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	86.50%
[1]	Includes an intercompany item eliminated in consolidation of $68 million.
[2]	Includes an intercompany item eliminated in consolidation of $75 million.
[3]	Includes an intercompany item eliminated in consolidation of $4 million.
[4]	Includes an intercompany item eliminated in consolidation of $4 million.
[5]	Includes an intercompany item eliminated in consolidation of $76 million.
[6]	Includes an intercompany item eliminated in consolidation of $97 million.

Property, Plant and Equipment80

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 25,559.8		$ 25,727.5
Property, Plant and Equipment, Transmission		14,247.9		12,433.4
Property, Plant and Equipment, Distribution		18,046.9		17,156.6
Property, Plant and Equipment, Other		3,722.9		5,073.1
Property, Plant and Equipment, Construction Work in Progress		3,903.9		3,215.3
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment				482
Accumulated Depreciation		19,348.2		19,970.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		46,133.2		43,635.1	[1]
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[4],[5]	2,019.6		1,835
Accretion Expense		101.4		95
Liabilities Incurred		58		42.8
Liabilities Settled		(147.2)	[6]	(34.2)
Revisions in Cash Flow Estimates		(115.5)	[7]	81
Ending Balance	[2],[3],[4],[5]	1,916.3		2,019.6		$ 1,835
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		131.9		102.9		72.7
Allowance for Borrowed Funds Used During Construction		61.3		44.5		39.8
Jointly-owned Electric Facilities
Utility Plant in Service		4,917.3		4,824.2
Construction Work in Progress		239.6		189.7
Accumulated Depreciation		1,773		1,679
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations Significant Change		95
Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		6,200.8		6,824
Property, Plant and Equipment, Transmission		2,408.1		2,228
Property, Plant and Equipment, Distribution		3,402.5		3,258.3
Property, Plant and Equipment, Other		345.5		373.5
Property, Plant and Equipment, Construction Work in Progress		475.1		321.5
Accumulated Depreciation		3,407.6		3,823.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,424.4		9,181.7
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4]	148.4		152.6
Accretion Expense		8.3		9.1
Liabilities Incurred		0		0
Liabilities Settled		(34)		(24)
Revisions in Cash Flow Estimates		17.5		10.7
Ending Balance	[3],[4]	140.2		148.4		152.6
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		13.8		7.1		2.3
Allowance for Borrowed Funds Used During Construction		$ 6.9		$ 3.8		$ 1.5
Appalachian Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		121 years		121 years		121 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		68 years		87 years		87 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		57 years		57 years		52 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		55 years		55 years		55 years
Appalachian Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		40 years		40 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		15 years		15 years		25 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		10 years		13 years		11 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		24 years		24 years
Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 3,841.7		$ 3,741.9
Property, Plant and Equipment, Transmission		1,406.9		1,358.4
Property, Plant and Equipment, Distribution		1,790.8		1,698.4
Property, Plant and Equipment, Other		662.3		1,490.8
Property, Plant and Equipment, Construction Work in Progress		519.8		537.2
Accumulated Depreciation		3,018		3,410.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,203.5		5,416.4
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4],[5]	1,342.5		1,255.2
Accretion Expense		64.3		60
Liabilities Incurred		0		0
Liabilities Settled		(5.7)		(1.4)
Revisions in Cash Flow Estimates		(147.3)		28.7
Ending Balance	[3],[4],[5]	1,253.8		1,342.5		$ 1,255.2
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		11.6		18.9		19.9
Allowance for Borrowed Funds Used During Construction		5		8		$ 9.8
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		1,180		1,270
Fair Value of Legally Restricted Assets		$ 1,800		$ 1,790
Indiana Michigan Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		75 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		45 years		45 years		45 years
Indiana Michigan Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		59 years		59 years		59 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		50 years		50 years		50 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		10 years		15 years		15 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		14 years		14 years
Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission		$ 2,235.6		$ 2,104.6
Property, Plant and Equipment, Distribution		4,287.7		4,087.6
Property, Plant and Equipment, Other		408.2		390.8
Property, Plant and Equipment, Construction Work in Progress		171.9		218.7
Accumulated Depreciation		2,048.7		2,038.1
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,054.7		4,763.6
Asset Retirement Obligations (ARO)
Beginning Balance	[3]	1.4		1.3
Accretion Expense		0		0.1
Liabilities Incurred		0		0
Liabilities Settled		0		0
Revisions in Cash Flow Estimates		0		0
Ending Balance	[3]	1.4		1.4		$ 1.3
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		8.8		6.9		5
Allowance for Borrowed Funds Used During Construction		$ 4.8		$ 4.4		$ 10.1
Ohio Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		60 years		60 years		60 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		57 years		57 years		60 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		50 years		50 years		50 years
Ohio Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		39 years		39 years		39 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		7 years		7 years		12 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		7 years		25 years
Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 1,302.6		$ 1,264.7
Property, Plant and Equipment, Transmission		815.4		788.9
Property, Plant and Equipment, Distribution		2,206.7		2,080.2
Property, Plant and Equipment, Other		405.7		421.6
Property, Plant and Equipment, Construction Work in Progress		315.3		204.8
Accumulated Depreciation		1,352.5		1,319.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,693.2		3,440.6
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4]	38.1		22.9
Accretion Expense		2.6		1.8
Liabilities Incurred		5.6		0
Liabilities Settled		(0.4)		(0.7)
Revisions in Cash Flow Estimates		1.9		14.1
Ending Balance	[3],[4]	47.8		38.1		$ 22.9
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		8.8		3.1		4.2
Allowance for Borrowed Funds Used During Construction		$ 5		$ 1.8		$ 2.3
Public Service Co Of Oklahoma [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		75 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		65 years		65 years		65 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		40 years		40 years		40 years
Public Service Co Of Oklahoma [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		35 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		40 years		40 years		40 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		7 years		30 years		30 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		5 years
Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 3,943.5		$ 3,864.5
Property, Plant and Equipment, Transmission		1,387.8		1,300.7
Property, Plant and Equipment, Distribution		1,957.3		1,894.6
Property, Plant and Equipment, Other		883.5		878.8
Property, Plant and Equipment, Construction Work in Progress		751.3		472
Accumulated Depreciation		2,602.3		2,503.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,321.1		5,907.3
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[4]	94.4		87.6
Accretion Expense		5.9		5.2
Liabilities Incurred		17.1		0
Liabilities Settled		(5)		(1.1)
Revisions in Cash Flow Estimates		13		2.7
Ending Balance	[2],[3],[4]	125.4		94.4		$ 87.6
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		26.4		11.9		7.4
Allowance for Borrowed Funds Used During Construction		14.8		6.9		$ 4.3
Jointly-owned Electric Facilities
Utility Plant in Service		2,684.9		2,632.9
Construction Work in Progress		210.3		160.7
Accumulated Depreciation		$ 769.1		$ 720.1
Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		65 years		65 years		65 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		51 years		51 years		51 years
Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		40 years		40 years		40 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		50 years		50 years		50 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		25 years		25 years		25 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		7 years		7 years
AEP Texas North Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		54.70%
W.C. Beckjord Generating Station (Unit No. 6) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]			12.50%
Utility Plant in Service	[8]			$ 0
Construction Work in Progress	[8]			0
Accumulated Depreciation	[8]			$ 0
Conesville Generating Station (Unit No. 4) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[9]	43.50%		43.50%
Utility Plant in Service	[9]	$ 337.4		$ 335.7
Construction Work in Progress	[9]	2.4		2.4
Accumulated Depreciation	[9]	$ 76.1		$ 65.9
J.M. Stuart Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[10]	26.00%		26.00%
Utility Plant in Service	[10]	$ 565.5		$ 552.7
Construction Work in Progress	[10]	12.9		11.5
Accumulated Depreciation	[10]	$ 221.8		$ 205.8
Wm. H. Zimmer Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[8]	25.40%		25.40%
Utility Plant in Service	[8]	$ 815.5		$ 812
Construction Work in Progress	[8]	6.4		4
Accumulated Depreciation	[8]	$ 421.7		$ 410.2
Dolet Hills Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[11]	40.20%		40.20%
Utility Plant in Service	[11]	$ 332.4		$ 329.7
Construction Work in Progress	[11]	3.9		3.7
Accumulated Depreciation	[11]	$ 205.9		$ 201.3
Dolet Hills Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[11]	40.20%		40.20%
Utility Plant in Service	[11]	$ 332.4		$ 329.7
Construction Work in Progress	[11]	3.9		3.7
Accumulated Depreciation	[11]	$ 205.9		$ 201.3
Flint Creek Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	50.00%		50.00%
Utility Plant in Service	[12]	$ 131.4		$ 125.1
Construction Work in Progress	[12]	195		119.6
Accumulated Depreciation	[12]	$ 70		$ 67.9
Flint Creek Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	50.00%		50.00%
Utility Plant in Service	[12]	$ 131.4		$ 125.1
Construction Work in Progress	[12]	195		119.6
Accumulated Depreciation	[12]	$ 70		$ 67.9
Pirkey Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	85.90%		85.90%
Utility Plant in Service	[12]	$ 572.1		$ 531.1
Construction Work in Progress	[12]	5.9		36.5
Accumulated Depreciation	[12]	$ 389.1		$ 381.1
Pirkey Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	85.90%		85.90%
Utility Plant in Service	[12]	$ 572.1		$ 531.1
Construction Work in Progress	[12]	5.9		36.5
Accumulated Depreciation	[12]	$ 389.1		$ 381.1
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[13]	70.30%		70.30%
Utility Plant in Service	[13]	$ 445.5		$ 409.1
Construction Work in Progress	[13]	7.2		10.3
Accumulated Depreciation	[13]	$ 236.2		$ 227.8
Oklaunion Generating Station (Unit No. 1) [Member] | Public Service Co Of Oklahoma [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[13]	15.60%		15.60%
Utility Plant in Service	[13]	$ 103		$ 94.7
Construction Work in Progress	[13]	1.8		2.6
Accumulated Depreciation	[13]	$ 58.2		$ 57.5
Turk Generating Plant [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	73.33%		73.33%
Utility Plant in Service	[12]	$ 1,649		$ 1,647
Construction Work in Progress	[12]	5.5		0.9
Accumulated Depreciation	[12]	$ 104.1		$ 69.8
Turk Generating Plant [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[12]	73.33%		73.33%
Utility Plant in Service	[12]	$ 1,649		$ 1,647
Construction Work in Progress	[12]	5.5		0.9
Accumulated Depreciation	[12]	$ 104.1		$ 69.8
Jointly Owned Electricity Transmission and Distribution System [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]
Utility Plant in Service		$ 68.5		$ 81.8
Construction Work in Progress		0.4		0.8
Accumulated Depreciation		$ 48.1		$ 49.2
Rockport Generating Plant (Unit No. 1) [Member] | Indiana Michigan Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[15],[16],[17]	50.00%		50.00%
Utility Plant in Service	[15],[16],[17]	$ 926.7		$ 801.5
Construction Work in Progress	[15],[16],[17]	58.5		119.9
Accumulated Depreciation	[15],[16],[17]	$ 512.4		492.2
Rockport Generating Plant (Unit No. 1) [Member] | AEP Generating Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		50.00%
Regulated Operation [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[18]	$ 19,082.8		18,394.1
Property, Plant and Equipment, Transmission		14,219		12,394.9
Property, Plant and Equipment, Distribution		18,046.9		17,156.6
Property, Plant and Equipment, Other		3,066.7		4,360.4
Property, Plant and Equipment, Construction Work in Progress	[18]	3,774.4		3,087.8
Accumulated Depreciation		16,076.9		16,461.8
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 42,112.9		$ 38,932
Regulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		81 years		87 years		87 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		75 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		75 years		75 years		75 years
Regulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		31 years		31 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		15 years		15 years		25 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		7 years		7 years		11 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		5 years
Regulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		3.50%		3.70%
Regulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		0.40%		1.70%		1.70%
Regulated Operation [Member] | Transmission [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.70%		2.70%
Regulated Operation [Member] | Transmission [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.40%		1.40%		1.10%
Regulated Operation [Member] | Distribution [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.70%		3.70%		3.80%
Regulated Operation [Member] | Distribution [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.40%		2.30%
Regulated Operation [Member] | Other Property Class [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		11.80%		8.60%		7.90%
Regulated Operation [Member] | Other Property Class [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.90%		2.10%		2.00%
Regulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 6,200.8		$ 6,824
Property, Plant and Equipment, Transmission		2,408.1		2,228
Property, Plant and Equipment, Distribution		3,402.5		3,258.3
Property, Plant and Equipment, Other		310.1		339.2
Property, Plant and Equipment, Construction Work in Progress		475.1		321.5
Accumulated Depreciation		3,395.5		3,811.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 9,401.1		$ 9,159.8
Regulated Operation [Member] | Appalachian Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		3.10%		3.00%
Regulated Operation [Member] | Appalachian Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.60%		1.70%		1.60%
Regulated Operation [Member] | Appalachian Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.60%		3.50%		3.50%
Regulated Operation [Member] | Appalachian Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		8.30%		6.90%		7.30%
Regulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 3,841.7		$ 3,741.9
Property, Plant and Equipment, Transmission		1,406.9		1,358.4
Property, Plant and Equipment, Distribution		1,790.8		1,698.4
Property, Plant and Equipment, Other		511.6		1,342.8
Property, Plant and Equipment, Construction Work in Progress		519.8		537.2
Accumulated Depreciation		2,908.3		3,302.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 5,162.5		$ 5,376.5
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.00%		1.90%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.70%		1.70%		1.50%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.80%		2.80%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		11.80%		6.10%		4.90%
Regulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 0		$ 0
Property, Plant and Equipment, Transmission		2,235.6		2,104.6
Property, Plant and Equipment, Distribution		4,287.7		4,087.6
Property, Plant and Equipment, Other		397.8		380.5
Property, Plant and Equipment, Construction Work in Progress		171.9		218.7
Accumulated Depreciation		2,047.9		2,037.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 5,045.1		$ 4,754.1
Regulated Operation [Member] | Ohio Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.30%		2.30%
Regulated Operation [Member] | Ohio Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.70%		2.70%
Regulated Operation [Member] | Ohio Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		7.20%		7.00%		7.50%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 1,302.6		$ 1,264.7
Property, Plant and Equipment, Transmission		815.4		788.9
Property, Plant and Equipment, Distribution		2,206.7		2,080.2
Property, Plant and Equipment, Other		400.5		416.4
Property, Plant and Equipment, Construction Work in Progress		315.3		204.8
Accumulated Depreciation		1,352.5		1,319.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 3,688		$ 3,435.4
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.70%		1.70%		1.70%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.90%		1.90%		1.90%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.40%		2.30%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		4.60%		4.10%		4.10%
Regulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[18]	$ 3,943.5		$ 3,864.5
Property, Plant and Equipment, Transmission		1,387.8		1,300.7
Property, Plant and Equipment, Distribution		1,957.3		1,894.6
Property, Plant and Equipment, Other		582.2		587.1
Property, Plant and Equipment, Construction Work in Progress	[18]	744.7		471.7
Accumulated Depreciation		2,445		2,360.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 6,170.5		$ 5,758.3
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.20%		2.20%		2.20%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.20%		2.30%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.60%		2.70%		2.60%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		5.50%		4.80%		5.00%
Unregulated Operation [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 4,020.3		$ 4,703.1	[1]
Unregulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		66 years		66 years		66 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		55 years		55 years		55 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life	[19]	50 years		50 years
Unregulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		35 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		43 years		43 years		43 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life	[19]	5 years		25 years
Unregulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.40%		3.40%		3.30%
Unregulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.50%		2.60%		2.60%
Unregulated Operation [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.30%		2.50%
Unregulated Operation [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		17.10%
Unregulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 23.3		$ 21.9
Unregulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		41		39.9
Unregulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9.6		9.5
Unregulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5.2		5.2
Unregulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 150.6		$ 149
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		20 years
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		3 years
Muskingum River Plant [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled		$ 81
Reduction in ARO Liability due to the execution of a joint use agreement with a third party [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates		$ 20
[1]	Amount excludes $482 million of Property, Plant and Equipment - Net classified as Assets from Discontinued Operations on the balance sheet. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	Includes ARO related to Sabine and DHLC.
[3]	Includes ARO related to asbestos removal.
[4]	Includes ARO related to ash disposal facilities.
[5]	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.18 billion and $1.27 billion as of December 31, 2015 and 2014.
[6]	Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7.
[7]	Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party.
[8]	Operated by Dynegy Corporation, a non-affiliated company. AEP’s portion of Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012.
[9]	Operated by AGR.
[10]	Operated by The Dayton Power & Light Company, a non-affiliated company.
[11]	Operated by CLECO, a non-affiliated company.
[12]	Operated by SWEPCo.
[13]	Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by TNC and various non-affiliated companies.
[14]	Varying percentages of ownership.
[15]	AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
[16]	Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13.
[17]	Operated by I&M.
[18]	SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
[19]	SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Cost Reduction Programs (Detail

Cost Reduction Programs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		$ 29.2
Incurred		2.7
Settled		22.6
Adjustments		0
Remaining Balance		$ 9.3	$ 29.2
Severance Costs			29.2
Disposition Plant Severance [Member] | Vertically Integrated Utilities [Member]
Cost Reduction Initiatives (Textuals) [Abstract]
Current Period Severance Costs Percentage		67.00%
Disposition Plant Severance [Member] | Generation and Marketing [Member]
Cost Reduction Initiatives (Textuals) [Abstract]
Current Period Severance Costs Percentage		33.00%
Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs				$ 7.7
Appalachian Power Co [Member] | Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		$ 9.3
Expense Allocation from AEPSC		0
Incurred		0.9
Settled	[1]	7
Adjustments		(0.1)
Remaining Balance		3.1	9.3
Severance Costs			7.1
Appalachian Power Co [Member] | Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs				0.3
Indiana Michigan Power Co [Member] | Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		8
Expense Allocation from AEPSC		0
Incurred		0.3
Settled		5.4
Adjustments		0
Remaining Balance		2.9	8
Severance Costs			8.2
Indiana Michigan Power Co [Member] | Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs				0.4
Ohio Power Co [Member] | Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs			0.1
Ohio Power Co [Member] | Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs				5.8
Public Service Co Of Oklahoma [Member] | Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		0.1
Expense Allocation from AEPSC		0
Incurred		0.3
Settled		0.2
Adjustments		0
Remaining Balance		0.2	0.1
Severance Costs			0.3
Public Service Co Of Oklahoma [Member] | Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Over-Accrual of Severance Costs				(0.1)
Southwestern Electric Power Co [Member] | Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		0.1
Expense Allocation from AEPSC		0
Incurred		0
Settled		0.1
Adjustments		0
Remaining Balance		$ 0	0.1
Severance Costs			$ 0.3
Southwestern Electric Power Co [Member] | Sustainable Cost Reductions [Member]
Cost Reduction Initiatives [Abstract]
Severance Costs				$ 1
[1]	ncludes amounts received from affiliates for expenses related to jointly-owned plant.

Unaudited Quarterly Financial82

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 3,614.7		$ 4,431.4		$ 3,826.7		$ 4,580.4		$ 3,819.1		$ 4,161.4		$ 3,900.6		$ 4,497.5		$ 16,453.2	$ 16,378.6	$ 14,813.5
Operating Income	466.4		960.2		804.1		1,102.8		429.5	[1]	904.9		760.7		1,032.3		3,333.5	3,127.4	2,822.5
Income from Continuing Operations	205.2		511.8		431.4		620.2		159.6		484.2		388.4		558.3		1,768.6	1,590.5	1,473.9
Income (Loss) from Discontinued Operations, Net of Tax	265.5	[2]	7.8		(0.1)		10.5		31.9		10.2		2.7		2.7		283.7	47.5	10.3
Net Income	470.7		519.6		431.3		630.7		191.5	[1]	494.4		391.1		561		2,052.3	1,638	1,484.2
Amounts Attributable to AEP Common Shareholders
Earnings Attributable To AEP Common Shareholders	$ 469.6		$ 518.3		$ 430		$ 629.2		$ 190.9		$ 493.2		$ 389.9		$ 559.8		$ 2,047.1	$ 1,633.8	$ 1,480.5
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.41	[3]	$ 1.04	[3]	$ 0.88	[3]	$ 1.27	[3]	$ 0.32		$ 0.99		$ 0.79		$ 1.14		$ 3.59	$ 3.24	$ 3.02
Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations	0.54	[4]	0.02	[4]	0	[4]	0.02	[4]	0.07	[3],[4]	0.02	[3],[4]	0.01	[3],[4]	0.01	[3],[4]	0.58	0.10	0.02
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	0.95	[3]	1.06	[3]	0.88	[3]	1.29	[3]	0.39	[3]	1.01	[3]	0.80	[3]	1.15	[3]	4.17	3.34	3.04
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations	0.41	[3]	1.04	[3]	0.88	[3]	1.27	[3]	0.32		0.99		0.79		1.14		3.59	3.24	3.02
Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations	0.54	[4]	0.02	[4]	0	[4]	0.02	[4]	0.07	[3],[4]	0.02	[3],[4]	0.01	[3],[4]	0.01	[3],[4]	0.58	0.10	0.02
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$ 0.95	[3]	$ 1.06	[3]	$ 0.88	[3]	$ 1.29	[3]	$ 0.39	[3]	$ 1.01	[3]	$ 0.80	[3]	$ 1.15	[3]	$ 4.17	$ 3.34	$ 3.04
Appalachian Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 655		$ 727.5		$ 682		$ 899		$ 735.1		$ 709.9		$ 694.7		$ 913.4		$ 2,963.5	$ 3,053.1	$ 3,417.4
Operating Income	133.7		157.9		145.7		273.5		107.3		130.2		110.7		220		710.8	568.2	506.3
Income from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0		0		0		0		0
Net Income	65.2		74.6		59		141.8		28.6		48.8		36.2		101.8		340.6	215.4	193.2
Indiana Michigan Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	487.3		568.3		544.3		586.3		531.1		542.9		533.9		641.8		2,186.2	2,249.7	2,366.9
Operating Income	50.7		103.4		91.4		124.4		39.2		62.9		57.1		146		369.9	305.2	321.9
Income from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0		0		0		0		0
Net Income	24.9		56.6		50.6		72.7		14.6		26.6		27.3		87.1		204.8	155.6	177.5
Ohio Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	692.2		782.3		705.8		918.4		871.4		839.2		786.1		880.2		3,148.7	3,376.9	4,762.6
Operating Income	100.5		140.9		96.5		122.9		99.1		104.7		114		115.7		460.8	433.5	793.1
Income from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0		0		0		0		0
Net Income	48		71.6		47.7		65.4		45		54.1		56.5		60.8		232.7	216.4	410
Public Service Co Of Oklahoma [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	292.6		420.3		319.5		306.8		314.4		417		318.8		301.4		1,339.2	1,351.6	1,295.5
Operating Income	18.3		84.5		55.5		34.9		27.2		87.4		48.9		25.3		193.2	188.8	211.2
Income from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0		0		0		0		0
Net Income	7		44.7		27.1		13.7		10.9		45.1		22.5		8.4		92.5	86.9	97.8
Southwestern Electric Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	378.6		532.5		438.1		431.7		424.7		531.8		449.3		440.6		1,780.9	1,846.4	1,795.8
Operating Income	25.6		141.2		110.1		92.3		46		133.2		78.8		64.7		369.2	322.7	343.8
Income from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0		0		0		0		0
Net Income	$ 7.7		$ 82.1		$ 59.5		$ 46.7		$ 14.2		$ 74.6		$ 32.8		$ 23		196	144.6	153.8
Amounts Attributable to AEP Common Shareholders
Earnings Attributable To AEP Common Shareholders																	$ 192.3	$ 140.4	$ 149.8
[1]	Includes termination of coal contract and a KPCo regulatory disallowance (see Note 4).
[2]	Includes sale of AEPRO (see Note 7).
[3]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[4]	Relates to sale of AEPRO (see Note 7).

Goodwill and Other Intangible83

Goodwill and Other Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Carrying Amount of Goodwill
Goodwill Total Balance		$ 52.5	$ 52.5
Impairment Losses		0	0
Goodwill Written Off Related to Sale of AEPRO		(38.8)
Goodwill and Other Intangible Assets (Textuals) [Abstract]
Acquired Intangible Assets Subject to Amortization		2	5
Amortization of Intangible Assets		3	5	$ 14
Estimated Total Amoritzation in 2016		$ 2
Acquired Customer Contracts [Member]
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class
Amortization Life		5 years
Gross Carrying Amount		$ 58.3	58.3
Accumulated Amortization		56.5	53.4
Corporate and Other [Member]
Changes in Carrying Amount of Goodwill
Goodwill Total Balance		37.1	75.9	75.9
Impairment Losses		0	0
Goodwill Written Off Related to Sale of AEPRO	[1]	(38.8)
Generation and Marketing [Member]
Changes in Carrying Amount of Goodwill
Goodwill Total Balance		15.4	15.4	15.4
Impairment Losses		$ 0	0
Balance Inclusive of AEP River Operations LLC [Member]
Changes in Carrying Amount of Goodwill
Goodwill Total Balance			$ 91.3	$ 91.3
[1]	The goodwill of $38.8 million related to AEPRO is included in Other Classes of Assets That Are Not Major as of December 31, 2014 in Note 7. See “Dispositions” section of Note 7 for additional information.