Indiana Michigan Power 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 01, 2016
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		491,711,533
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Vertically Integrated Utilities	$ 2,538.3	$ 2,435.8	$ 6,864.6	$ 7,081.8
Transmission and Distribution Utilities	1,245.4	1,163.6	3,398.9	3,377.9
Generation & Marketing	823.3	801.8	2,192.5	2,288.6
Other Revenues	45.2	30.2	134	90.2
TOTAL REVENUES	4,652.2	4,431.4	12,590	12,838.5
Expenses
Fuel and Other Consumables Used for Electric Generation	880.1	955.9	2,236.1	2,782.4
Purchased Electricity for Resale	774	730.8	2,134.6	2,050
Other Operation	771.1	689.9	2,150.7	1,954.6
Maintenance	286.3	311.5	854.4	923.1
Asset Impairments and Other Related Charges	2,264.9	0	2,264.9	0
Depreciation and Amortization	539.3	534.9	1,550.2	1,528
Taxes Other Than Income Taxes	264.4	248.2	767.9	733.3
TOTAL EXPENSES	5,780.1	3,471.2	11,958.8	9,971.4
OPERATING INCOME (LOSS)	(1,127.9)	960.2	631.2	2,867.1
Other Income (Expense):
Interest and Investment Income	2	1.6	6.5	6.1
Carrying Costs Income	1.7	1.8	11.9	18.4
Allowance for Equity Funds Used During Construction	25.6	32.6	86.1	96.4
Interest Expense	(225.3)	(220.2)	(667.2)	(658.1)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	(1,323.9)	776	68.5	2,329.9
Income Tax Expense (Credit)	(534.5)	275.6	(134)	827.1
Equity Earnings (Loss) of Unconsolidated Subsidiaries	25.2	11.4	42.8	60.6
Income (Loss) from Continuing Operations	(764.2)	511.8	245.3	1,563.4
Income (Loss) from Discontinued Operations, Net of Tax	0	7.8	(2.5)	18.2
Net Income (Loss)	(764.2)	519.6	242.8	1,581.6
Net Income Attributable to Noncontrolling Interests	1.6	1.3	5.3	4.1
Earnings Attributable to Common Shareholders	$ (765.8)	$ 518.3	$ 237.5	$ 1,577.5
Earnings Per Share
Weighted Average Number of Basic AEP Common Shares Outstanding	491,697,809	490,648,929	491,422,921	490,155,315
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ (1.56)	$ 1.04	$ 0.49	$ 3.18
Basic Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations	0	0.02	(0.01)	0.04
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ (1.56)	$ 1.06	$ 0.48	$ 3.22
Weighted Average Number of Diluted AEP Common Shares Outstanding	491,813,858	490,800,335	491,596,861	490,411,020
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ (1.56)	$ 1.04	$ 0.49	$ 3.18
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations	0	0.02	(0.01)	0.04
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	(1.56)	1.06	0.48	3.22
Common Stock, Dividends Per Share, Declared	$ 0.56	$ 0.53	$ 1.68	$ 1.59
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	$ 739	$ 685.3	$ 2,153.3	$ 2,184.9
Sales to AEP Affiliates	36.4	39.3	109	115.7
Other Revenues	2.8	2.9	9.4	7.9
TOTAL REVENUES	778.2	727.5	2,271.7	2,308.5
Expenses
Fuel and Other Consumables Used for Electric Generation	190.1	188.5	494.1	595.3
Purchased Electricity for Resale	69.2	80.5	240.9	258.9
Other Operation	117.6	101.8	349.4	311.6
Maintenance	66.8	70.5	196.3	179.8
Depreciation and Amortization	98.1	96.3	290	292.7
Taxes Other Than Income Taxes	32	32	93.9	93.1
TOTAL EXPENSES	573.8	569.6	1,664.6	1,731.4
OPERATING INCOME (LOSS)	204.4	157.9	607.1	577.1
Other Income (Expense):
Interest Income	0.3	0.3	0.8	1.2
Carrying Costs Income	0	0.1	0.2	0.8
Allowance for Equity Funds Used During Construction	4.5	3.4	9.1	10.3
Interest Expense	(46.4)	(46.6)	(140.7)	(145.6)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	162.8	115.1	476.5	443.8
Income Tax Expense (Credit)	58.7	40.5	172.7	168.4
Net Income (Loss)	104.1	74.6	303.8	275.4
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	574.7	536.2	1,570.8	1,617.5
Sales to AEP Affiliates	3.9	9.6	22.4	16.6
Other Revenues - Affiliated	15.6	21.7	46.3	62.2
Other Revenues	3.4	0.8	13.2	2.6
TOTAL REVENUES	597.6	568.3	1,652.7	1,698.9
Expenses
Fuel and Other Consumables Used for Electric Generation	91.3	90.5	236.8	264.4
Purchased Electricity for Resale	43.7	41.5	134.3	147.7
Purchased Electricity from AEP Affiliates	64.5	67.2	165.9	182.2
Other Operation	138.9	141	413.9	407.3
Maintenance	45.7	53.8	134.6	160.9
Asset Impairments and Other Related Charges	10.5	0	10.5	0
Depreciation and Amortization	49.1	49.3	143.2	150.2
Taxes Other Than Income Taxes	22.5	21.6	71.5	67
TOTAL EXPENSES	466.2	464.9	1,310.7	1,379.7
OPERATING INCOME (LOSS)	131.4	103.4	342	319.2
Other Income (Expense):
Interest Income	1.7	1.9	9.1	7.2
Allowance for Equity Funds Used During Construction	4.1	2.1	10.9	9.1
Interest Expense	(26.7)	(23.1)	(76.3)	(68.9)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	110.5	84.3	285.7	266.6
Income Tax Expense (Credit)	35.1	27.7	84.3	86.7
Net Income (Loss)	75.4	56.6	201.4	179.9
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	864.4	775.9	2,349.2	2,320.4
Sales to AEP Affiliates	5.5	4.4	11.7	79.7
Other Revenues	1.4	2	4.8	6.4
TOTAL REVENUES	871.3	782.3	2,365.7	2,406.5
Expenses
Purchased Electricity for Resale	203.4	173.1	516.1	431.6
Purchased Electricity from AEP Affiliates	35.9	45.8	121.4	462.6
Amortization of Generation Deferrals	66.1	55.4	173	122.2
Other Operation	184.2	170.2	525.9	446.8
Maintenance	38.8	39.4	104.4	121.2
Depreciation and Amortization	69.4	63.7	189	178.6
Taxes Other Than Income Taxes	101.9	93.8	291.7	283.2
TOTAL EXPENSES	699.7	641.4	1,921.5	2,046.2
OPERATING INCOME (LOSS)	171.6	140.9	444.2	360.3
Other Income (Expense):
Interest Income	0.7	1.2	3	4.3
Carrying Costs Income	0.9	(1.6)	4	10
Allowance for Equity Funds Used During Construction	0.3	2.2	3.7	7
Interest Expense	(27.2)	(32.6)	(87.7)	(96.3)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	146.3	110.1	367.2	285.3
Income Tax Expense (Credit)	46.4	38.5	122.5	100.6
Net Income (Loss)	99.9	71.6	244.7	184.7
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	400.9	418.6	971.3	1,040.9
Sales to AEP Affiliates	0.1	1.1	2	3.5
Other Revenues	0.7	0.6	2.9	2.2
TOTAL REVENUES	401.7	420.3	976.2	1,046.6
Expenses
Fuel and Other Consumables Used for Electric Generation	16.4	87.7	43	226.3
Purchased Electricity for Resale	130.8	103.2	315.3	253.8
Purchased Electricity from AEP Affiliates	3.2	0	3.6	0
Other Operation	81	77.5	211.8	199.3
Maintenance	25.6	27.2	71.6	74.3
Depreciation and Amortization	37.2	30.9	109.9	90.2
Taxes Other Than Income Taxes	9.1	9.3	27.8	27.8
TOTAL EXPENSES	303.3	335.8	783	871.7
OPERATING INCOME (LOSS)	98.4	84.5	193.2	174.9
Other Income (Expense):
Interest Income	0.2	0.2	0.5	0.3
Allowance for Equity Funds Used During Construction	1.1	2.4	4.9	6
Interest Expense	(14.9)	(15)	(44.6)	(44.4)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	84.8	72.1	154	136.8
Income Tax Expense (Credit)	32	27.4	56.6	51.3
Net Income (Loss)	52.8	44.7	97.4	85.5
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	530.5	526	1,324.1	1,387.7
Sales to AEP Affiliates	8.6	5.9	20	13.1
Other Revenues	0.6	0.6	1.6	1.5
TOTAL REVENUES	539.7	532.5	1,345.7	1,402.3
Expenses
Fuel and Other Consumables Used for Electric Generation	158.8	180	403.3	463.1
Purchased Electricity for Resale	35.9	23.6	97.5	70.8
Other Operation	89.2	81.4	243.3	214.8
Maintenance	33.8	34.4	102	100.1
Depreciation and Amortization	51.2	48.9	148.1	143.8
Taxes Other Than Income Taxes	23.4	23	66.8	66.1
TOTAL EXPENSES	392.3	391.3	1,061	1,058.7
OPERATING INCOME (LOSS)	147.4	141.2	284.7	343.6
Other Income (Expense):
Interest Income	0	0	0	1.2
Allowance for Equity Funds Used During Construction	0.1	7.1	9.5	18.2
Interest Expense	(32.6)	(29.2)	(92)	(91.4)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	114.9	119.1	202.2	271.6
Income Tax Expense (Credit)	33.2	37.4	53.9	85.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries	2.7	0.4	4.9	2.1
Net Income (Loss)	84.4	82.1	153.2	188.3
Net Income Attributable to Noncontrolling Interests	1.1	1	3.3	3
Earnings Attributable to Common Shareholders	$ 83.3	$ 81.1	$ 149.9	$ 185.3

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net Income (Loss)	$ (764.2)	$ 519.6	$ 242.8	$ 1,581.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(28.6)	(5.3)	(20.8)	(10.7)
Securities Available for Sale, Net of Tax	0.5	(1.3)	1.7	(1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.2	0.3	0.4	0.9
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(27.9)	(6.3)	(18.7)	(10.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	(792.1)	513.3	224.1	1,570.8
Total Comprehensive Income Attributable to Noncontrolling Interest	1.6	1.3	5.3	4.1
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	(793.7)	512	218.8	1,566.7
Appalachian Power Co [Member]
Net Income (Loss)	104.1	74.6	303.8	275.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.2)	(0.6)	(0.1)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.3)	(0.5)	(1)	(1.4)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.5)	(0.7)	(1.6)	(1.5)
TOTAL COMPREHENSIVE INCOME (LOSS)	103.6	73.9	302.2	273.9
Indiana Michigan Power Co [Member]
Net Income (Loss)	75.4	56.6	201.4	179.9
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.3	0.3	1	0.8
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.3	1	0.8
TOTAL COMPREHENSIVE INCOME (LOSS)	75.7	56.9	202.4	180.7
Ohio Power Co [Member]
Net Income (Loss)	99.9	71.6	244.7	184.7
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.3)	(1)	(1)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(1)	(1)
TOTAL COMPREHENSIVE INCOME (LOSS)	99.7	71.3	243.7	183.7
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	52.8	44.7	97.4	85.5
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.2)	(0.1)	(0.6)	(0.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)			(0.6)	(0.5)
TOTAL COMPREHENSIVE INCOME (LOSS)	52.6	44.6	96.8	85
Southwestern Electric Power Co [Member]
Net Income (Loss)	84.4	82.1	153.2	188.3
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	0.4	0.4	1.3	1.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.1)	(0.2)	(0.5)	(0.7)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.3	0.2	0.8	0.8
TOTAL COMPREHENSIVE INCOME (LOSS)	84.7	82.3	154	189.1
Total Comprehensive Income Attributable to Noncontrolling Interest	1.1	1	3.3	3
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 83.6	$ 81.3	$ 150.7	$ 186.1

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Cash Flow Hedges, Tax	$ (15.4)	$ (2.9)	$ (11.2)	$ (5.8)
Securities Available for Sale, Tax	0.3	(0.7)	1	(0.5)
Amortization of Pension and OPEB Deferred Costs, Tax	0.1	0.2	0.2	0.5
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	0
Amortization of Pension and OPEB Deferred Costs, Tax	(0.1)	(0.2)	(0.5)	(0.7)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.1	0.1	0.5	0.4
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.1)	(0.2)	(0.5)	(0.6)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.1)	(0.1)	(0.3)	(0.3)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.2	0.2	0.7	0.8
Amortization of Pension and OPEB Deferred Costs, Tax	$ (0.1)	$ (0.1)	$ (0.3)	$ (0.4)

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]
Beginning 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
Beginning Balance, Shares at Dec. 31, 2014							509,700,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	67.9						$ 9.1						58.8
Issuance of Common Stock, Shares							1,400,000
Common Stock Dividends	(783.4)																		(780.3)
Common Stock Dividends		(181.3)	(90)	(156.3)		(90)														(181.3)	(90)	(156.3)		(90)
Common Stock Dividends						(3.1)																									(3.1)	(3.1)
Other Changes in Equity	24.6												19.6																		5
Net Income (Loss)	1,577.5					185.3													1,577.5					185.3
Net Income Attributable to Noncontrolling Interests	4.1					3																									4.1	3
Net Income (Loss)	1,581.6	275.4	179.9	184.7	85.5	188.3														275.4	179.9	184.7	85.5
Other Comprehensive Income (Loss)	(10.8)	(1.5)	0.8	(1)	(0.5)	0.8																			(10.8)	(1.5)	0.8	(1)	(0.5)	0.8
Contribution of Mutual Energy SWEPCo, LLC from Parent						2												2
Pension and OPEB Adjustment Related to Mitchell Plant	5.1																								5.1
Ending Balance at Sep. 30, 2015	17,709.5	3,459.5	2,044.7	2,007.6	1,113.2	2,195.2	$ 3,322.4	260.4	56.6	321.2	157.2	135.7	6,281.8	1,809.6	980.9	838.8	364	676.6	8,203.8	1,386	1,020.7	843	587.5	1,389.3	(108.8)	3.5	(13.5)	4.6	4.5	(6.7)	10.3	0.3
Ending Balance, Shares at Sep. 30, 2015							511,100,000
Beginning Balance at Dec. 31, 2015	$ 17,904.9	3,475	2,036.4	1,986.6	$ 1,119.9	2,169.7	$ 3,324	260.4	56.6	321.2	157.2	135.7	6,296.5	1,828.7	980.9	838.8	364	676.6	8,398.3	1,388.7	1,015.6	822.3	594.5	1,366.3	(127.1)	(2.8)	(16.7)	4.3	4.2	(9.4)	13.2	0.5
Beginning Balance, Shares at Dec. 31, 2015	511,389,173				10,482,000		511,400,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	$ 34.2						$ 4.3						29.9
Issuance of Common Stock, Shares							600,000
Common Stock Dividends	(829.8)																		(826.4)
Common Stock Dividends		(225)	(93.8)	(150)		(90)														(225)	(93.8)	(150)		(90)
Common Stock Dividends						(3.5)																									(3.4)	(3.5)
Other Changes in Equity	9.6												3.6																		6
Net Income (Loss)	237.5					149.9													237.5					149.9
Net Income Attributable to Noncontrolling Interests	5.3					3.3																									5.3	3.3
Net Income (Loss)	242.8	303.8	201.4	244.7	$ 97.4	153.2														303.8	201.4	244.7	97.4
Other Comprehensive Income (Loss)	(18.7)	(1.6)	1	(1)	(0.6)	0.8																			(18.7)	(1.6)	1	(1)	(0.6)	0.8
Contribution of Mutual Energy SWEPCo, LLC from Parent						0
Ending Balance at Sep. 30, 2016	$ 17,343	$ 3,552.2	$ 2,145	$ 2,080.3	$ 1,216.7	$ 2,230.2	$ 3,328.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,330	$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 7,809.4	$ 1,467.5	$ 1,123.2	$ 917	$ 691.9	$ 1,426.2	$ (145.8)	$ (4.4)	$ (15.7)	$ 3.3	$ 3.6	$ (8.6)	$ 21.1	$ 0.3
Ending Balance, Shares at Sep. 30, 2016	512,046,044				10,482,000		512,000,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 212.2	$ 176.4
Other Temporary Investments		279.2	386.8
Accounts Receivable:
Customers		628.4	615.9
Accrued Unbilled Revenues		166.7	31.2
Pledged Accounts Receivable - AEP Credit		1,065.5	940.3
Miscellaneous		59.9	82.1
Allowance for Uncollectible Accounts		(40.5)	(29)
Total Accounts Receivable		1,880	1,640.5
Fuel		468	600.8
Materials and Supplies		556.8	738.6
Risk Management Assets		110.8	134.4
Accrued Tax Benefits		214.9	58.9
Regulatory Asset for Under-Recovered Fuel Costs		107.4	115.2
Margin Deposits		56.5	107.3
Assets Held for Sale		1,915.3	0
Prepayments and Other Current Assets		148.1	113.5
TOTAL CURRENT ASSETS		5,949.2	4,072.4
Property, Plant and Equipment
Generation		19,684.2	25,559.8
Transmission		15,157.8	14,247.9
Distribution		18,639	18,046.9
Other Property, Plant and Equipment		3,467.5	3,722.9
Construction Work in Progress		3,651.3	3,903.9
Total Property, Plant and Equipment		60,599.8	65,481.4
Accumulated Depreciation and Amortization		16,337.6	19,348.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		44,262.2	46,133.2
Other Noncurrent Assets
Regulatory Assets		5,182.4	5,140.3
Securitized Assets		1,559	1,749.9
Spent Nuclear Fuel and Decommissioning Trusts		2,230.8	2,106.4
Goodwill		52.5	52.5
Long-term Risk Management Assets		311.7	321.8
Deferred Charges and Other Noncurrent Assets		1,894.2	2,106.6
TOTAL OTHER NONCURRENT ASSETS		11,230.6	11,477.5
TOTAL ASSETS		61,442	61,683.1
Current Liabilities
Accounts Payable		1,340.3	1,418
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	750	675
Other Short-term Debt		728.3	125
Total Short-term Debt		1,478.3	800
Long-term Debt Due Within One Year		2,384.8	1,831.8
Risk Management Liabilities		79.3	87.1
Customer Deposits		341.6	346.6
Accrued Taxes		666.2	979.1
Accrued Interest		230.2	226.9
Regulatory Liability for Over-Recovered Fuel Costs		7.9	113.9
Liabilities Held for Sale		231	0
Other Current Liabilities		1,019.8	1,305.1
TOTAL CURRENT LIABILITIES		7,779.4	7,108.5
Noncurrent Liabilities
Long-term Debt		17,319.9	17,740.9
Long-term Risk Management Liabilities		240	179.1
Deferred Income Taxes		11,815.1	11,733.2
Regulatory Liabilities and Deferred Investment Tax Credits		3,887.5	3,736.1
Asset Retirement Obligations		1,858	1,806.5
Employee Benefits and Pension Obligations		497	583.3
Deferred Credits and Other Noncurrent Liabilities		702.1	890.6
TOTAL NONCURRENT LIABILITIES		36,319.6	36,669.7
TOTAL LIABILITIES		44,099	43,778.2
Rate Matters
Commitments and Contingencies
Equity
Common Stock		3,328.3	3,324
Paid-in Capital		6,330	6,296.5
Retained Earnings		7,809.4	8,398.3
Accumulated Other Comprehensive Income (Loss)		(145.8)	(127.1)
TOTAL COMMON SHAREHOLDER'S EQUITY		17,321.9	17,891.7
Noncontrolling Interests		21.1	13.2
TOTAL EQUITY		17,343	17,904.9
TOTAL LIABILITIES AND EQUITY		61,442	61,683.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.3	2.8
Restricted Cash for Securitized Funding		7.8	14.8
Advances to Affiliates		24.4	25.6
Accounts Receivable:
Customers		115.4	120.9
Affiliated Companies		54.3	51.2
Accrued Unbilled Revenues		42.3	17.9
Miscellaneous		1.1	2.2
Allowance for Uncollectible Accounts		(4.7)	(4.3)
Total Accounts Receivable		208.4	187.9
Fuel		124.8	119.3
Materials and Supplies		100	127
Risk Management Assets		3.2	14.7
Risk Management Assets - Affiliated		0	0.9
Accrued Tax Benefits		16	30.6
Regulatory Asset for Under-Recovered Fuel Costs		71.6	86.9
Prepayments and Other Current Assets		17.4	17.4
TOTAL CURRENT ASSETS		576.9	627.9
Property, Plant and Equipment
Generation		6,319.5	6,200.8
Transmission		2,555.3	2,408.1
Distribution		3,519.2	3,402.5
Other Property, Plant and Equipment		368.7	345.5
Construction Work in Progress		481.9	475.1
Total Property, Plant and Equipment		13,244.6	12,832
Accumulated Depreciation and Amortization		3,598.1	3,407.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,646.5	9,424.4
Other Noncurrent Assets
Regulatory Assets		1,123	1,154.2
Securitized Assets		311	328
Long-term Risk Management Assets		0.2	0.1
Deferred Charges and Other Noncurrent Assets		110.7	113.7
TOTAL OTHER NONCURRENT ASSETS		1,544.9	1,596
TOTAL ASSETS		11,768.3	11,648.3
Current Liabilities
Advances from Affiliates		84.1	181
Accounts Payable		174.1	196.5
Affiliated Companies		74.8	67.7
Short-term Debt:
Long-term Debt Due Within One Year		503.1	318
Risk Management Liabilities		10.7	4.8
Customer Deposits		81.8	83.9
Accrued Taxes		51.8	79.5
Accrued Interest		63.3	40.6
Other Current Liabilities		127.1	153.4
TOTAL CURRENT LIABILITIES		1,170.8	1,125.4
Noncurrent Liabilities
Long-term Debt		3,530	3,612.7
Long-term Risk Management Liabilities		0.3	0.1
Deferred Income Taxes		2,632.9	2,527
Regulatory Liabilities and Deferred Investment Tax Credits		628.8	637.1
Asset Retirement Obligations		91.2	98.9
Employee Benefits and Pension Obligations		103	114.4
Deferred Credits and Other Noncurrent Liabilities		59.1	57.7
TOTAL NONCURRENT LIABILITIES		7,045.3	7,047.9
TOTAL LIABILITIES		8,216.1	8,173.3
Rate Matters
Commitments and Contingencies
Equity
Common Stock		260.4	260.4
Paid-in Capital		1,828.7	1,828.7
Retained Earnings		1,467.5	1,388.7
Accumulated Other Comprehensive Income (Loss)		(4.4)	(2.8)
TOTAL EQUITY		3,552.2	3,475
TOTAL LIABILITIES AND EQUITY		11,768.3	11,648.3
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.6	1.1
Advances to Affiliates		12.4	11.7
Accounts Receivable:
Customers		46.3	43.9
Affiliated Companies		47.6	68.7
Accrued Unbilled Revenues		2.2	0.1
Miscellaneous		0.9	2.6
Allowance for Uncollectible Accounts		(0.1)	(0.1)
Total Accounts Receivable		96.9	115.2
Fuel		48.6	46.5
Materials and Supplies		156.2	185.9
Risk Management Assets		5.2	10.6
Risk Management Assets - Affiliated		0	1.7
Accrued Tax Benefits		26.5	40.5
Prepayments and Other Current Assets		50.1	42.1
TOTAL CURRENT ASSETS		397.5	455.3
Property, Plant and Equipment
Generation		3,996.3	3,841.7
Transmission		1,437.7	1,406.9
Distribution		1,866.7	1,790.8
Other Property, Plant and Equipment		623.8	662.3
Construction Work in Progress		607.9	519.8
Total Property, Plant and Equipment		8,532.4	8,221.5
Accumulated Depreciation and Amortization		3,063.9	3,018
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,468.5	5,203.5
Other Noncurrent Assets
Regulatory Assets		837.6	804.3
Spent Nuclear Fuel and Decommissioning Trusts		2,230.8	2,106.4
Long-term Risk Management Assets		0.2	0
Deferred Charges and Other Noncurrent Assets		136.6	140.9
TOTAL OTHER NONCURRENT ASSETS		3,205.2	3,051.6
TOTAL ASSETS		9,071.2	8,710.4
Current Liabilities
Advances from Affiliates		26.3	294.3
Accounts Payable		140.2	201
Affiliated Companies		61.9	61.8
Short-term Debt:
Long-term Debt Due Within One Year		176.1	162.9
Risk Management Liabilities		1.3	6.3
Customer Deposits		34.2	35.7
Accrued Taxes		43.7	74.2
Accrued Interest		11.8	26.2
Obligations Under Capital Leases		8.7	32.8
Other Current Liabilities		131.6	142.1
TOTAL CURRENT LIABILITIES		635.8	1,037.3
Noncurrent Liabilities
Long-term Debt		2,231.3	1,837.1
Long-term Risk Management Liabilities		0.2	1.6
Deferred Income Taxes		1,510.9	1,361.5
Regulatory Liabilities and Deferred Investment Tax Credits		1,148.6	1,076.2
Asset Retirement Obligations		1,291.1	1,240.9
Deferred Credits and Other Noncurrent Liabilities		108.3	119.4
TOTAL NONCURRENT LIABILITIES		6,290.4	5,636.7
TOTAL LIABILITIES		6,926.2	6,674
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6	56.6
Paid-in Capital		980.9	980.9
Retained Earnings		1,123.2	1,015.6
Accumulated Other Comprehensive Income (Loss)		(15.7)	(16.7)
TOTAL EQUITY		2,145	2,036.4
TOTAL LIABILITIES AND EQUITY		9,071.2	8,710.4
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		4	3.1
Restricted Cash for Securitized Funding		16.1	27.7
Advances to Affiliates		0.2	331.1
Accounts Receivable:
Customers		13.8	46.4
Affiliated Companies		54.1	64.3
Accrued Unbilled Revenues		35.1	1.4
Miscellaneous		0.7	0.4
Allowance for Uncollectible Accounts		(0.2)	(0.2)
Total Accounts Receivable		103.5	112.3
Materials and Supplies		48.8	61.5
Emission Allowances		18.3	24.6
Accrued Tax Benefits		11.5	1.8
Prepayments and Other Current Assets		16.3	11.1
TOTAL CURRENT ASSETS		218.7	573.2
Property, Plant and Equipment
Transmission		2,287.3	2,235.6
Distribution		4,401.7	4,287.7
Other Property, Plant and Equipment		436.7	408.2
Construction Work in Progress		194.1	171.9
Total Property, Plant and Equipment		7,319.8	7,103.4
Accumulated Depreciation and Amortization		2,107.1	2,048.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,212.7	5,054.7
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3	32.3
Regulatory Assets		1,016.4	1,113
Securitized Assets		68	85.9
Long-term Risk Management Assets		0	19.2
Deferred Charges and Other Noncurrent Assets		116	259.6
TOTAL OTHER NONCURRENT ASSETS		1,232.7	1,510
TOTAL ASSETS		6,664.1	7,137.9
Current Liabilities
Accounts Payable		152.9	156.4
Affiliated Companies		90.9	88.7
Short-term Debt:
Long-term Debt Due Within One Year		46.4	395.9
Risk Management Liabilities		5.6	3.6
Customer Deposits		71.2	65.4
Accrued Taxes		246.6	528.3
Accrued Interest		38.4	33
Other Current Liabilities		87	154.3
TOTAL CURRENT LIABILITIES		739	1,425.6
Noncurrent Liabilities
Long-term Debt		1,717	1,761.8
Long-term Risk Management Liabilities		103.5	0
Deferred Income Taxes		1,414	1,383.2
Regulatory Liabilities and Deferred Investment Tax Credits		555.7	514.2
Employee Benefits and Pension Obligations		27.7	35.8
Deferred Credits and Other Noncurrent Liabilities		26.9	30.7
TOTAL NONCURRENT LIABILITIES		3,844.8	3,725.7
TOTAL LIABILITIES		4,583.8	5,151.3
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2	321.2
Paid-in Capital		838.8	838.8
Retained Earnings		917	822.3
Accumulated Other Comprehensive Income (Loss)		3.3	4.3
TOTAL EQUITY		2,080.3	1,986.6
TOTAL LIABILITIES AND EQUITY		6,664.1	7,137.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		2	1.4
Advances to Affiliates		51.1	80.6
Accounts Receivable:
Customers		17.8	26
Affiliated Companies		23.5	20.8
Miscellaneous		4.4	3.3
Allowance for Uncollectible Accounts		(0.6)	(0.6)
Total Accounts Receivable		45.1	49.5
Fuel		21.8	17.6
Materials and Supplies		50.1	51.9
Risk Management Assets		1.1	0.6
Accrued Tax Benefits		7.6	37.3
Regulatory Asset for Under-Recovered Fuel Costs		4.1	0
Prepayments and Other Current Assets		10.8	6.5
TOTAL CURRENT ASSETS		193.7	245.4
Property, Plant and Equipment
Generation		1,552.1	1,302.6
Transmission		832.1	815.4
Distribution		2,284.4	2,206.7
Other Property, Plant and Equipment		243	405.7
Construction Work in Progress		127.9	315.3
Total Property, Plant and Equipment		5,039.5	5,045.7
Accumulated Depreciation and Amortization		1,297.4	1,352.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,742.1	3,693.2
Other Noncurrent Assets
Regulatory Assets		322.2	214.8
Employee Benefits and Pension Assets		15.7	10.6
Deferred Charges and Other Noncurrent Assets		18.1	6.4
TOTAL OTHER NONCURRENT ASSETS		356	231.8
TOTAL ASSETS		4,291.8	4,170.4
Current Liabilities
Accounts Payable		116.7	108.2
Affiliated Companies		40.3	51.5
Short-term Debt:
Long-term Debt Due Within One Year		125.5	275.4
Risk Management Liabilities		0	0.2
Customer Deposits		50.2	50.3
Accrued Taxes		39.3	23.6
Accrued Interest		14.5	15.1
Regulatory Liability for Over-Recovered Fuel Costs		0	76.1
Other Current Liabilities		55	64.4
TOTAL CURRENT LIABILITIES		441.5	664.8
Noncurrent Liabilities
Long-term Debt		1,160.7	1,010.7
Deferred Income Taxes		1,055	971.8
Regulatory Liabilities and Deferred Investment Tax Credits		340	335.1
Asset Retirement Obligations		52.5	39.9
Employee Benefits and Pension Obligations		13.8	14.5
Deferred Credits and Other Noncurrent Liabilities		11.6	13.7
TOTAL NONCURRENT LIABILITIES		2,633.6	2,385.7
TOTAL LIABILITIES		3,075.1	3,050.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2	157.2
Paid-in Capital		364	364
Retained Earnings		691.9	594.5
Accumulated Other Comprehensive Income (Loss)		3.6	4.2
TOTAL EQUITY		1,216.7	1,119.9
TOTAL LIABILITIES AND EQUITY		4,291.8	4,170.4
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		15.2	5.2
Advances to Affiliates		299.4	2
Accounts Receivable:
Customers		25	40.2
Affiliated Companies		30.4	22
Miscellaneous		22.4	27.1
Allowance for Uncollectible Accounts		(1.6)	(0.9)
Total Accounts Receivable		76.2	88.4
Fuel		109.4	142.1
Materials and Supplies		70.8	71.5
Risk Management Assets		1.4	0.8
Regulatory Asset for Under-Recovered Fuel Costs		0.8	4.1
Prepayments and Other Current Assets		21	21.2
TOTAL CURRENT ASSETS		594.2	335.3
Property, Plant and Equipment
Generation		4,581.9	3,943.5
Transmission		1,487.6	1,387.8
Distribution		1,994.5	1,957.3
Other Property, Plant and Equipment		707.1	883.5
Construction Work in Progress		188.5	751.3
Total Property, Plant and Equipment		8,959.6	8,923.4
Accumulated Depreciation and Amortization		2,572.4	2,602.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,387.2	6,321.1
Other Noncurrent Assets
Regulatory Assets		500.7	415.8
Deferred Charges and Other Noncurrent Assets		116.2	75.8
TOTAL OTHER NONCURRENT ASSETS		616.9	491.6
TOTAL ASSETS		7,598.3	7,148
Current Liabilities
Advances from Affiliates		0	58.3
Accounts Payable		129.3	150.4
Affiliated Companies		51.6	78.8
Short-term Debt:
Long-term Debt Due Within One Year		354	3.3
Risk Management Liabilities		0	3.1
Customer Deposits		61.8	61.4
Accrued Taxes		74	58.3
Accrued Interest		23	43
Obligations Under Capital Leases		16.8	21.9
Other Current Liabilities		81	110.7
TOTAL CURRENT LIABILITIES		791.5	589.2
Noncurrent Liabilities
Long-term Debt		2,320	2,270.2
Long-term Risk Management Liabilities		0	2.1
Deferred Income Taxes		1,562.1	1,399.8
Regulatory Liabilities and Deferred Investment Tax Credits		446.9	448.8
Asset Retirement Obligations		127.4	117.5
Employee Benefits and Pension Obligations		26.6	25.8
Obligations Under Capital Leases		68.5	75.6
Deferred Credits and Other Noncurrent Liabilities		25.1	49.3
TOTAL NONCURRENT LIABILITIES		4,576.6	4,389.1
TOTAL LIABILITIES		5,368.1	4,978.3
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7	135.7
Paid-in Capital		676.6	676.6
Retained Earnings		1,426.2	1,366.3
Accumulated Other Comprehensive Income (Loss)		(8.6)	(9.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,229.9	2,169.2
Noncontrolling Interests		0.3	0.5
TOTAL EQUITY		2,230.2	2,169.7
TOTAL LIABILITIES AND EQUITY		$ 7,598.3	$ 7,148
[1]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Condensed Consolidated Balance7

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 212.2	$ 176.4
Other Temporary Investments	279.2	386.8
Fuel	468	600.8
Property, Plant and Equipment
Other Property, Plant and Equipment	3,467.5	3,722.9
Accumulated Depreciation and Amortization	16,337.6	19,348.2
Current Liabilities
Long-term Debt Due Within One Year	2,384.8	1,831.8
Noncurrent Liabilities
Long-term Debt	$ 17,319.9	$ 17,740.9
Equity
Common Stock, Par Value Per Share	$ 6.50	$ 6.50
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	512,046,044	511,389,173
Treasury Stock, Shares	20,336,592	20,336,592
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 3.3	$ 2.8
Fuel	124.8	119.3
Property, Plant and Equipment
Other Property, Plant and Equipment	368.7	345.5
Accumulated Depreciation and Amortization	3,598.1	3,407.6
Current Liabilities
Long-term Debt Due Within One Year	503.1	318
Noncurrent Liabilities
Long-term Debt	$ 3,530	$ 3,612.7
Equity
Common Stock, Shares Authorized	30,000,000	30,000,000
Common Stock, Shares Outstanding	13,499,500	13,499,500
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1.6	$ 1.1
Fuel	48.6	46.5
Property, Plant and Equipment
Other Property, Plant and Equipment	623.8	662.3
Accumulated Depreciation and Amortization	3,063.9	3,018
Current Liabilities
Long-term Debt Due Within One Year	176.1	162.9
Noncurrent Liabilities
Long-term Debt	$ 2,231.3	$ 1,837.1
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	2,500,000	2,500,000
Common Stock, Shares Outstanding	1,400,000	1,400,000
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 97.8	$ 84.6
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	4	3.1
Property, Plant and Equipment
Other Property, Plant and Equipment	436.7	408.2
Accumulated Depreciation and Amortization	2,107.1	2,048.7
Current Liabilities
Long-term Debt Due Within One Year	46.4	395.9
Noncurrent Liabilities
Long-term Debt	$ 1,717	$ 1,761.8
Equity
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 46.3	$ 45.9
Noncurrent Liabilities
Long-term Debt	93.7	139.4
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	2	1.4
Fuel	21.8	17.6
Property, Plant and Equipment
Other Property, Plant and Equipment	243	405.7
Accumulated Depreciation and Amortization	1,297.4	1,352.5
Current Liabilities
Long-term Debt Due Within One Year	125.5	275.4
Noncurrent Liabilities
Long-term Debt	$ 1,160.7	$ 1,010.7
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	$ 15.2	$ 5.2
Fuel	109.4	142.1
Property, Plant and Equipment
Other Property, Plant and Equipment	707.1	883.5
Accumulated Depreciation and Amortization	2,572.4	2,602.3
Current Liabilities
Long-term Debt Due Within One Year	354	3.3
Noncurrent Liabilities
Long-term Debt	$ 2,320	$ 2,270.2
Equity
Common Stock, Par Value Per Share	$ 18	$ 18
Common Stock, Shares Authorized	7,600,000	7,600,000
Common Stock, Shares Outstanding	7,536,640	7,536,640
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Current Assets
Cash and Cash Equivalents	$ 12.8	$ 3.7
Fuel	33.4	40.4
Property, Plant and Equipment
Other Property, Plant and Equipment	282.4	297.7
Accumulated Depreciation and Amortization	160.2	157.3
AEP Subsidiaries [Member]
Current Assets
Other Temporary Investments	270.5	376.6
Current Liabilities
Long-term Debt Due Within One Year	393.4	410.4
Noncurrent Liabilities
Long-term Debt	$ 1,727.6	$ 1,971.4

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating Activities
Net Income (Loss)	$ 242.8	$ 1,581.6
Income (Loss) from Discontinued Operations	(2.5)	18.2
Income (Loss) from Continuing Operations	245.3	1,563.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,550.2	1,528
Deferred Income Taxes	(47)	528.6
Asset Impairments and Other Related Charges	2,264.9	0
Carrying Costs Income	(11.9)	(18.4)
Allowance for Equity Funds Used During Construction	(86.1)	(96.4)
Mark-to-Market of Risk Management Contracts	56.6	17.7
Amortization of Nuclear Fuel	109.7	101.6
Pension Contributions to Qualified Plan Trust	(84.8)	(91.8)
Property Taxes	288.3	247.1
Deferred Fuel Over/Under-Recovery, Net	(28.5)	93.3
Deferral of Ohio Capacity Costs, Net	108.8	35
Change in Other Noncurrent Assets	(231.5)	(114.3)
Change in Other Noncurrent Liabilities	41.3	8.9
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(240.8)	(17.5)
Fuel, Materials and Supplies	11.6	193.8
Accounts Payable	47.8	(13.3)
Accrued Taxes, Net	(393)	(68.3)
Other Current Assets	31.5	10.5
Other Current Liabilities	(211.4)	2.8
Net Cash Flows from (Used for) Operating Activities	3,421	3,910.7
Investing Activities
Construction Expenditures	(3,387)	(3,282.7)
Change in Other Temporary Investments, Net	109.2	80.8
Purchases of Investment Securities	(2,454.5)	(1,489.4)
Sales of Investment Securities	2,427	1,437.3
Acquisitions of Nuclear Fuel	(127.6)	(53.3)
Other Investing Activities	4.2	58.9
Net Cash Flows from (Used for) Investing Activities	(3,428.7)	(3,248.4)
Financing Activities
Issuance of Common Stock	34.2	67.9
Issuance of Long-term Debt	1,559.6	2,931.1
Change in Short-term Debt, Net	678.3	(564)
Retirement of Long-term Debt	(1,307.6)	(2,131.4)
Make Whole Premium on Extinguishment of Long-term Debt	0	(92.7)
Principal Payments for Capital Lease Obligations	(81.9)	(73.9)
Dividends Paid on Common Stock	(829.8)	(783.4)
Other Financing Activities	(6.8)	(0.9)
Net Cash Flows from (Used for) Financing Activities	46	(647.3)
Cash Flows from Discontinued Operations
Operating Activities	(2.5)	10.1
Investing Activities	0	2.5
Financing Activities	0	(12.3)
Net Increase (Decrease) in Cash and Cash Equivalents	35.8	15.3
Cash and Cash Equivalents at Beginning of Period	176.4	162.5
Cash and Cash Equivalents at End of Period	212.2	177.8
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	637	639.1
Net Cash Paid (Received) for Income Taxes	32.2	115.6
Noncash Acquisitions Under Capital Leases	65.8	96.9
Construction Expenditures Included in Current Liabilities as of September 30,	604.8	579.4
Construction Expenditures Included in Noncurrent Liabilities as of September 30,	0	66.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0.3	31.1
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	303.8	275.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	290	292.7
Deferred Income Taxes	100.9	179.1
Carrying Costs Income	(0.2)	(0.8)
Allowance for Equity Funds Used During Construction	(9.1)	(10.3)
Mark-to-Market of Risk Management Contracts	18.4	(5.9)
Pension Contributions to Qualified Plan Trust	(8.8)	(10)
Property Taxes	29.2	28
Deferred Fuel Over/Under-Recovery, Net	19	(1.7)
Change in Other Noncurrent Assets	(5.1)	(33.2)
Change in Other Noncurrent Liabilities	(23)	(26.7)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(20.5)	28.8
Fuel, Materials and Supplies	(1.2)	31.4
Accounts Payable	4.9	2.7
Accrued Taxes, Net	(13.9)	(75.3)
Other Current Assets	(0.2)	(2.6)
Other Current Liabilities	(4.1)	15.4
Net Cash Flows from (Used for) Operating Activities	680.1	687
Investing Activities
Construction Expenditures	(472.7)	(456.7)
Change in Restricted Cash for Securitized Funding	7	8.2
Change in Advances to Affiliates, Net	1.2	25
Other Investing Activities	10.6	10.6
Net Cash Flows from (Used for) Investing Activities	(453.9)	(412.9)
Financing Activities
Issuance of Long-term Debt	314.1	726.3
Change in Advances from Affiliates, Net	(96.9)	35.2
Retirement of Long-term Debt	(213.6)	(672.5)
Repayments of Related Party Debt	0	(86)
Make Whole Premium on Extinguishment of Long-term Debt	0	(92.7)
Principal Payments for Capital Lease Obligations	(4.7)	(3.8)
Dividends Paid on Common Stock	(225)	(181.3)
Other Financing Activities	0.4	0.5
Net Cash Flows from (Used for) Financing Activities	(225.7)	(274.3)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.5	(0.2)
Cash and Cash Equivalents at Beginning of Period	2.8	2.6
Cash and Cash Equivalents at End of Period	3.3	2.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	113.2	128.4
Net Cash Paid (Received) for Income Taxes	55.8	33.7
Noncash Acquisitions Under Capital Leases	2.1	2.3
Construction Expenditures Included in Current Liabilities as of September 30,	66.8	81
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	201.4	179.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	143.2	150.2
Deferred Income Taxes	116.2	38.3
Asset Impairments and Other Related Charges	10.5	0
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(17.4)	(0.1)
Allowance for Equity Funds Used During Construction	(10.9)	(9.1)
Mark-to-Market of Risk Management Contracts	0.5	12.9
Amortization of Nuclear Fuel	109.7	101.6
Pension Contributions to Qualified Plan Trust	(12.7)	(14.6)
Deferred Fuel Over/Under-Recovery, Net	6.1	(16.1)
Change in Other Noncurrent Assets	0	26.4
Change in Other Noncurrent Liabilities	30	9.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	17	5.5
Fuel, Materials and Supplies	(1.1)	29.6
Accounts Payable	(17.9)	(14)
Accrued Taxes, Net	(16.5)	4.6
Other Current Assets	6.7	7
Other Current Liabilities	(27.8)	(9.3)
Net Cash Flows from (Used for) Operating Activities	537	502
Investing Activities
Construction Expenditures	(405.1)	(337)
Change in Advances to Affiliates, Net	(0.7)	0
Purchases of Investment Securities	(2,452.9)	(1,479.1)
Sales of Investment Securities	2,427	1,437.3
Acquisitions of Nuclear Fuel	(127.6)	(53.3)
Other Investing Activities	7.8	9
Net Cash Flows from (Used for) Investing Activities	(551.5)	(423.1)
Financing Activities
Issuance of Long-term Debt	482.7	210.7
Change in Advances from Affiliates, Net	(268)	8.5
Retirement of Long-term Debt	(76.8)	(178.5)
Principal Payments for Capital Lease Obligations	(29.8)	(29.9)
Dividends Paid on Common Stock	(93.8)	(90)
Other Financing Activities	0.7	0.6
Net Cash Flows from (Used for) Financing Activities	15	(78.6)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.5	0.3
Cash and Cash Equivalents at Beginning of Period	1.1	1
Cash and Cash Equivalents at End of Period	1.6	1.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	85.6	77.5
Net Cash Paid (Received) for Income Taxes	(36)	17.2
Noncash Acquisitions Under Capital Leases	16.8	2
Construction Expenditures Included in Current Liabilities as of September 30,	83.4	51.6
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30,	0.3	31.1
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	0.1	2.1
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	244.7	184.7
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	189	178.6
Amortization Of Generation Deferrals	173	122.2
Deferred Income Taxes	28.6	28.1
Carrying Costs Income	(4)	(10)
Allowance for Equity Funds Used During Construction	(3.7)	(7)
Mark-to-Market of Risk Management Contracts	124.7	31.8
Pension Contributions to Qualified Plan Trust	(7.1)	(7.7)
Property Taxes	169.1	148.4
Purchased Electricity Over Under Recovery Net	(21.1)	(15.7)
Deferral of Ohio Capacity Costs, Net	0	(30.7)
Change in Other Noncurrent Assets	(124.9)	27.8
Change in Other Noncurrent Liabilities	17.2	32.3
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	8.8	41.2
Fuel, Materials and Supplies	0.5	(15)
Accounts Payable	2	(78.8)
Accrued Taxes, Net	(291.1)	(134.7)
Other Current Assets	(4.5)	(3.2)
Other Current Liabilities	(26.9)	1.7
Net Cash Flows from (Used for) Operating Activities	474.3	494
Investing Activities
Construction Expenditures	(276.4)	(346.8)
Change in Restricted Cash for Securitized Funding	11.6	12.5
Change in Advances to Affiliates, Net	330.9	33.3
Proceeds from Notes Receivable Affiliated	0	86
Other Investing Activities	9	10.9
Net Cash Flows from (Used for) Investing Activities	75.1	(204.1)
Financing Activities
Retirement of Long-term Debt	(395.9)	(131.5)
Principal Payments for Capital Lease Obligations	(3.1)	(2.9)
Dividends Paid on Common Stock	(150)	(156.3)
Other Financing Activities	0.5	1.2
Net Cash Flows from (Used for) Financing Activities	(548.5)	(289.5)
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.9	0.4
Cash and Cash Equivalents at Beginning of Period	3.1	2.9
Cash and Cash Equivalents at End of Period	4	3.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	78.2	79
Net Cash Paid (Received) for Income Taxes	178	24.1
Noncash Acquisitions Under Capital Leases	2.4	2.1
Construction Expenditures Included in Current Liabilities as of September 30,	30	30.2
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	97.4	85.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	109.9	90.2
Deferred Income Taxes	79.5	40.1
Allowance for Equity Funds Used During Construction	(4.9)	(6)
Mark-to-Market of Risk Management Contracts	(0.7)	(1.9)
Pension Contributions to Qualified Plan Trust	(5.6)	(5.8)
Property Taxes	(8)	(8)
Deferred Fuel Over/Under-Recovery, Net	(80.2)	76.9
Change in Other Noncurrent Assets	(18.8)	(13.6)
Change in Other Noncurrent Liabilities	(3.7)	8.2
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	4.4	(2.6)
Fuel, Materials and Supplies	(2.4)	(1.1)
Accounts Payable	23.1	(9.3)
Accrued Taxes, Net	45.4	21
Other Current Assets	(2.2)	(1.9)
Other Current Liabilities	(1.1)	8
Net Cash Flows from (Used for) Operating Activities	232.1	279.7
Investing Activities
Construction Expenditures	(266.8)	(262.9)
Change in Advances to Affiliates, Net	29.5	(116.3)
Other Investing Activities	8.7	7.6
Net Cash Flows from (Used for) Investing Activities	(228.6)	(371.6)
Financing Activities
Issuance of Long-term Debt	150	248.8
Change in Advances from Affiliates, Net	0	(154.2)
Retirement of Long-term Debt	(150.3)	(0.3)
Principal Payments for Capital Lease Obligations	(3)	(2.8)
Other Financing Activities	0.4	0.7
Net Cash Flows from (Used for) Financing Activities	(2.9)	92.2
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	0.6	0.3
Cash and Cash Equivalents at Beginning of Period	1.4	1.4
Cash and Cash Equivalents at End of Period	2	1.7
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	45	40.6
Net Cash Paid (Received) for Income Taxes	(50.3)	12.8
Noncash Acquisitions Under Capital Leases	2.2	1.5
Construction Expenditures Included in Current Liabilities as of September 30,	20.2	37.3
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	153.2	188.3
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	148.1	143.8
Deferred Income Taxes	141.9	45.7
Allowance for Equity Funds Used During Construction	(9.5)	(18.2)
Mark-to-Market of Risk Management Contracts	(5.8)	(0.3)
Pension Contributions to Qualified Plan Trust	(8.3)	(8.1)
Property Taxes	(13.7)	(13)
Deferred Fuel Over/Under-Recovery, Net	1.2	11.7
Change in Other Noncurrent Assets	18.4	2
Change in Other Noncurrent Liabilities	(25.8)	(1.1)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	12.2	2.8
Fuel, Materials and Supplies	33.4	24.8
Accounts Payable	(17.2)	(17.1)
Accrued Taxes, Net	14.1	53.1
Accrued Interest	(20)	(21.2)
Other Current Assets	(2.4)	2.8
Other Current Liabilities	(24.8)	(23.7)
Net Cash Flows from (Used for) Operating Activities	395	372.3
Investing Activities
Construction Expenditures	(315.3)	(408.3)
Change in Advances to Affiliates, Net	(297.4)	(2)
Other Investing Activities	(1.9)	4.4
Net Cash Flows from (Used for) Investing Activities	(614.6)	(405.9)
Financing Activities
Issuance of Long-term Debt	402.2	446
Change in Advances from Affiliates, Net	(58.3)	0
Retirement of Long-term Debt	(3.3)	(306.8)
Principal Payments for Capital Lease Obligations	(18.6)	(13.4)
Dividends Paid on Common Stock	(90)	(90)
Dividends Paid on Common Stock	(3.5)	(3.1)
Other Financing Activities	1.1	0.8
Net Cash Flows from (Used for) Financing Activities	229.6	33.5
Cash Flows from Discontinued Operations
Net Increase (Decrease) in Cash and Cash Equivalents	10	(0.1)
Cash and Cash Equivalents at Beginning of Period	5.2	14.4
Cash and Cash Equivalents at End of Period	15.2	14.3
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	107.6	106.1
Net Cash Paid (Received) for Income Taxes	(66.6)	12.3
Noncash Acquisitions Under Capital Leases	5.5	1.5
Construction Expenditures Included in Current Liabilities as of September 30,	54.3	85.3
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent	0	(2)
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC	$ 0	$ 2

Significant Accounting Matters

Significant Accounting Matters	9 Months Ended
	Sep. 30, 2016
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .
Appalachian Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .
Indiana Michigan Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .
Ohio Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .
Public Service Co Of Oklahoma [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .
Southwestern Electric Power Co [Member]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 . Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of operations: Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18 There were no antidilutive shares outstanding as of September 30, 2016 and 2015 .

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2016
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
Appalachian Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
Indiana Michigan Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
Ohio Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
Public Service Co Of Oklahoma [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.
Southwestern Electric Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized on the statements of income in each reporting period. Management is analyzing the impact of this new standard and the related ASUs that clarify guidance in the standard. At this time, management cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. 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 the Registrants’ results of operations, financial position or cash flows. Management plans to adopt ASU 2015-11 prospectively, effective January 1, 2017. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented as well as a number of optional practical expedients that entities may elect to apply. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management expects the new standard to impact the Registrants’ financial position, but not the Registrants’ results of operations or cash flows. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. The new accounting guidance is effective for annual periods beginning after December 15, 2016. Early adoption is permitted in any interim or annual period. Certain provisions require retrospective/modified retrospective transition while others are to be applied prospectively. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption. Management plans to adopt ASU 2016-09 effective January 1, 2017. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020.

Comprehensive Income

Comprehensive Income	9 Months Ended
	Sep. 30, 2016
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )
Appalachian Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )
Indiana Michigan Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )
Ohio Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )
Public Service Co Of Oklahoma [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )
Southwestern Electric Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and nine months ended September 30, 2016 and 2015 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )

Rate Matters

Rate Matters	9 Months Ended
	Sep. 30, 2016
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t
Ohio Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t
Public Service Co Of Oklahoma [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in the 2015 Annual Report, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2015 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2016 and updates the 2015 Annual Report. Regulatory Assets Pending Final Regulatory Approval AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9 APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3 I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3 OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3 PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4 SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters (Applies to AEP and APCo) 2016 West Virginia Expanded Net Energy Cost Filing In June 2016, the WVPSC approved a settlement agreement related to APCo and WPCo’s combined annual ENEC filing. The settlement agreement included $38 million ( $30 million related to APCo) of additional ENEC revenues and $17 million ( $14 million related to APCo) in construction surcharges annually for two years, effective July 2016. Additionally, APCo and WPCo agreed that a general rate case will not be filed before April 2018. West Virginia Deferred Base Rate Increase In May 2015, the WVPSC issued an order on APCo and WPCo’s combined base rate case. 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. In June 2016, the WVPSC issued an order that approved recovery of the total deferred billing, including carrying charges through June 2018, totaling $29 million ( $27 million related to APCo). Recovery was approved over two years, effective July 2016. Additionally, at the end of the two-year amortization, any over/under-recovery of the delayed billing will be included in the annual ENEC filing. The WVPSC also approved implementation of the prospective $25 million base rate increase effective July 2016. 2015 Virginia Regulatory Asset Proceeding In 2015, the Virginia SCC initiated a proceeding to address the treatment of APCo’s authorized regulatory assets. In September 2016, the Virginia SCC issued an order that approved the continued recovery through amortization of certain regulatory assets established prior to the period of frozen rates pursuant to the amended Virginia law (see “Virginia Legislation Affecting Biennial Reviews” below). 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 amendments provide 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 in 2016. In July 2016, the Virginia SCC issued an order that denied the petition. In July 2016, intervenors, including certain APCo industrial customers, filed an appeal of the order with the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. As of September 30, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $545 million based upon interim rate increases received from 2009 through 2016. During a November 2015 open meeting at the PUCT, ETT committed 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 revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) Indiana Amended PJM Settlement Agreement In September 2016, I&M and certain intervenors filed an amended settlement agreement with the IURC. This agreement amends a previously approved 2014 settlement agreement that addresses the recovery of 43.5% of certain transmission expenses through the Indiana PJM rider through 2017. The amended agreement allows I&M to recover 100% of the Indiana jurisdictional share of these transmission expenses not recovered through base rates through the Indiana PJM rider, subject to a $109 million cap for the period January 2017 through June 2018. Beginning July 2018, I&M will be allowed to recover 100% of the Indiana jurisdictional share of these transmission expenses through the Indiana PJM rider, without a cap, until the issue is addressed by the IURC in a future proceeding, subject to the condition that I&M files a base rate case on or before January 2018. The amended agreement also provides for deferral of incremental vegetation management expenses over the period January 2017 through June 2018. Any vegetation management expenses deferred would reduce the cap for the transmission expenses described above. As part of the amended settlement, I&M agreed that it will not file a base rate case before July 2017 and will not implement new base rates prior to July 2018. A hearing at the IURC was held in October 2016. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs, depreciation over a 10-year life and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case In January 2016, 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 August 2016, the TRA approved a settlement agreement that included an $8 million annual increase in base rates with a 9.85% return on common equity effective September 2016. 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 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s 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 weighted average cost of capital (WACC) rate. In 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and remanded the matter back to the PUCO for reinstatement of the WACC rate. In June 2016, the PUCO approved OPCo’s proposed increase to the PIRR rates, in accordance with the Supreme Court of Ohio ruling. The increase to PIRR rates included $146 million in additional carrying charges and the recovery of $40 million in additional under-recovered fuel costs resulting from a decrease in customer demand. The increase is effective July 2016 through December 2018. In July 2016, intervenors filed requests for rehearing with the PUCO, which the PUCO granted in August 2016. If the PUCO determines after rehearing that the additional PIRR carrying charges are not recoverable, it could reduce future net income and cash flows and impact financial condition. 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. In 2013, this ruling was generally upheld in PUCO rehearing orders. In July 2012, the PUCO issued an order in a separate capacity proceeding requiring OPCo to 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 included reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In April 2016, the Supreme Court of Ohio issued two opinions related to the deferral of OPCo’s capacity charges. In one of the opinions, the Supreme Court of Ohio ruled that the PUCO must reconsider an energy credit that was used to determine OPCo’s authorized capacity deferral threshold of $188.88/MW day during the August 2012 through May 2015 period. The PUCO reduced OPCo’s authorized capacity deferral threshold to $188.88/MW day largely due to an offset for an energy credit of $147.41 /MW day. The Supreme Court of Ohio directed the PUCO to substantively address OPCo’s arguments that the $147.41/MW day credit was overstated by approximately $100 /MW day due to various inaccuracies affecting input data and assumptions. 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 modified and approved 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. As of September 30, 2016 , OPCo’s net deferred capacity costs balance was $239 million , including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. In April 2016, the second Supreme Court of Ohio opinion rejected a portion of OPCo’s RSR revenues collected during the period September 2012 through May 2015 and directed the PUCO to reduce OPCo’s deferred capacity costs by these previously collected RSR revenues. The Supreme Court of Ohio was not able to determine the amount of the reduction to OPCo’s deferred capacity costs and remanded the issue to the PUCO to determine the appropriate reduction. As directed by the PUCO, in May 2016, OPCo submitted revised RSR tariffs that reflect the RSR being collected subject to refund. In April 2016, the Supreme Court of Ohio also ruled favorably on OPCo’s cross-appeal regarding a previously PUCO-imposed SEET threshold under the ESP and remanded this issue to the PUCO. See “Significantly Excessive Earnings Test Filings” section below. 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 November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. 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 with the PUCO for the period August 2012 through May 2015. 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. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. In June 2016, OPCo filed a request with the PUCO that requested a consolidated procedural schedule to resolve interrelated proceedings including (a) OPCo’s deferral of capacity costs for the period August 2012 through May 2015, (b) the implementation of OPCo’s RSR and (c) the concerns related to the recovery of fixed fuel costs through both the FAC and the approved capacity charges. As part of the filing, OPCo requested that its net deferred capacity costs balance as of May 31, 2015 increase by $157 million , including carrying charges through September 2016. This net increase consists of a $327 million decrease due to the non-deferral portion of the RSR collections and an increase of $484 million for the correction of the energy credit. Recovery of the $157 million was requested to be effective October 2016 through December 2018. Additionally, OPCo filed testimony supporting the position that double recovery of fixed fuel costs could not have occurred because OPCo was unable to fully recover its capacity costs, which included fixed fuel costs, even with a corrected energy credit. Due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, management believes that the PUCO will rule upon these issues together. Further, management believes that the net impact of these issues will not result in a material future reduction of OPCo’s net income. The recovery of fixed fuel costs will be addressed in a separate hearing scheduled for January 2017. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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 and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a 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 May 2015, OPCo filed an amended PPA application that (a) included OPCo’s OVEC contractual entitlement (OVEC PPA), (b) addressed the PPA requirements set forth in the PUCO’s February 2015 order and (c) 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 (Affiliate PPA). In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. The approved PPA rider is effective April 2016 through May 2024, subject to audit and review by the PUCO. The stipulation agreement, as approved, included (a) an Affiliate PPA between OPCo and AGR to be included in the PPA rider, (b) OPCo’s OVEC PPA to be included in the PPA rider, (c) potential additional contingent customer credits of up to $100 million to be included in the PPA rider over the final four years of the PPA rider and (d) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MW and a wind energy project(s) of at least 500 MW, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. OPCo agreed to file a carbon reduction plan with the PUCO by December 2016 that will focus on fuel diversification and carbon emission reductions. In March 2016, a group of merchant generation owners filed a complaint at the FERC against PJM seeking revisions to the Minimum Offer Price Rule (MOPR) in PJM’s tariff. Although the complaint requested the FERC act in advance of the May 2016 Base Residual Auction for the 2019/2020 delivery year, the complaint is still pending without a decision from the FERC. If approved as proposed, the revised MOPR could affect future bidding behavior for units with cost recovery mechanisms. In April 2016, the FERC issued an order granting a January 2016 complaint filed against AGR and OPCo. The FERC order rescinded the waivers of the FERC’s affiliate rules as to the affiliate PPA between AGR and OPCo. As a result, AGR and OPCo cannot implement the affiliate PPA without the FERC review, in accordance with FERC’s rules governing affiliate transactions. As a result of the April 2016 FERC order, management does not intend to pursue the affiliate PPA. In May 2016, OPCo filed an application for rehearing with the PUCO related to certain aspects of the March 2016 PUCO order. The application included a proposed OVEC-only PPA Rider that included an option for the rider to be bypassable. The proposed OVEC-only PPA Rider included (a) the elimination of the PUCO-imposed customer-specific rate impact cap of 5% through May 2018, (b) modifications to proportionately decrease the amount of the potential customer credits and (c) the inclusion of PJM capacity performance penalties within the PPA rider. Also in May 2016, intervenors filed applications for rehearing with the PUCO opposing the modified and approved stipulation agreement. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO does not accept the requested modifications. Consistent with the terms of the modified and approved stipulation agreement, in May 2016, OPCo filed an amended ESP that proposed to extend the ESP through May 2024. The amended ESP included (a) an extension of the PPA rider, which includes only OPCo’s entitlements to its ownership percentage of OVEC, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Generation Resource Rider. Based upon a September 2016 PUCO order, OPCo will refile its ESP extension application and supporting testimony in November 2016. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings Background Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric distribution utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. 2009 SEET Filing In 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 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 ® ( gridSMART ® Phase II) program was filed with the PUCO which included a proposed project to satisfy the PUCO 2009 SEET directive. In April 2016, a stipulation agreement related to the gridSMART ® Phase II program was filed with the PUCO. As part of the stipulation agreement, OPCo will invest at least $20 million over a six-year period for the installation of Volt VAR Optimization (VVO) technology on selected circuits throughout OPCo’s service territory. All parties to the stipulation agree that OPCo’s proposed VVO investment resolves OPCo’s outstanding obligation for renewable or similar investment associated with the PUCO’s 2009 SEET directive. A hearing at the PUCO on the stipulation was held in August 2016. A decision from the PUCO is pending. 2014 and 2015 SEET Filing The PUCO established an annual SEET earnings threshold of 12% during the June 2012 - May 2015 ESP period. In May 2013, OPCo filed a cross appeal with the Supreme Court of Ohio, asserting that the SEET threshold would not be based on the earnings of comparable publicly traded companies as originally required by the SEET statute. In April 2016, the Supreme Court of Ohio agreed with OPCo’s cross-appeal assertion that a 12% SEET threshold was not based on the applicable Ohio SEET statute. The Supreme Court of Ohio reversed the 12% threshold and remanded this issue to the PUCO. A decision from the PUCO is pending. In June 2015 and May 2016, OPCo submitted its SEET filings for 2014 and 2015, respectively, with the PUCO. In August 2016, intervenors filed testimony recommending a revenue refund of approximately $20 million for 2014 and no refund for 2015 based upon a new approach to determine significantly excessive earnings that has not been previously approved by the PUCO. In September 2016, OPCo and the PUCO staff filed a stipulation agreement with the PUCO stating that no significantly excessive earnings occurred for 2014 or 2015. In September 2016, intervenors filed testimony opposing the stipulation agreement. Management believes its financial statements adequately address the impact of 2014 and 2015 SEET requirements. 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. A hearing at the PUCO is scheduled for January 2017 to jointly review the recovery of fixed fuel costs as well as the open FAC audits discussed 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. In OPCo’s 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. Through September 2009, the last month of the interim arrangement, OPCo had approximately $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 filing to approve recovery of the deferral under the interim agreement. Of the $64 million in deferred FAC costs, approximately 50% was related to Columbus Southern Power Company (CSPCo) and 50% related to OPCo, prior to the merger of CSPCo into OPCo in December 2011. CSPCo’s portion of these deferred fuel costs has been recovered as a result of the previous collections of CSPCo fuel costs from ratepayers and the PUCO’s 2013 order to apply CSPCo’s 2010 excessive earnings to offset CSPCo’s final deferred fuel balance. OPCo’s share of Ormet deferred fuel costs continues to be recovered through OPCo’s PIRR. To the extent amounts discussed above are refunded to customers, 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 t

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Appalachian Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Ohio Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Public Service Co Of Oklahoma [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Southwestern Electric Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants’ business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2015 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees unless specified below. 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 . In June 2016, the $1.75 billion credit facility due in June 2017 was amended to $3 billion due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. Also in June 2016, the $1.75 billion credit facility due in July 2018 was amended to $500 million due in June 2018. As of September 30, 2016 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $300 million . As of September 30, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017 The Registrants have $291 million of variable rate Pollution Control Bonds supported by $295 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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017 Guarantees of Third-Party Obligations (Applies to AEP and SWEPCo) As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2016 , SWEPCo has collected $68 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 $53 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets. 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 September 30, 2016 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2016 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $11 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2016 . 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 September 30, 2016 , 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 Segment)” section of Note 6 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of September 30, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $87 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of September 30, 2016 , AEP’s boat and barge lease guarantee liability was $14 million , of which $3 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of September 30, 2016 , 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. 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. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The 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 remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The 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. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, Plaintiffs filed a notice of appeal on whether AEGCo and I&M are in breach of certain contract provisions that Plaintiffs allege operate to protect the Plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing Plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. This matter is currently pending before the U.S. Court of Appeals for the Sixth Circuit. 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. In May 2016, the district court dismissed the remaining case. Management will continue to defend any appeal of that matter. 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 February 2016, PSO filed a motion for summary judgment. In April 2016, by opinion and order, the court granted PSO’s motion for summary judgment and dismissed the case. Plaintiffs did not appeal the dismissal and the court’s order is final. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. 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, which typically handles multi-plaintiff cases, rather than back to the Mason County, West Virginia Circuit Court. Defendants’ petition for rehearing was denied by the West Virginia Supreme Court. Management will continue to defend against the claims. Management believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.

Dispositions, Assets and Liabil

Dispositions, Assets and Liabilities Held for Sale and Impairments	9 Months Ended
	Sep. 30, 2016
Dispositions, Assets and Liabilities Held for Sale and Impairments	DISPOSITIONS, ASSETS AND LIABILITIES HELD FOR SALE AND IMPAIRMENTS The disclosures in this note apply to AEP only unless indicated otherwise. DISPOSITIONS 2016 Tanners Creek Plant (Vertically Integrated Utilities Segment) (Applies to AEP and I&M) In October 2016, I&M sold its retired Tanners Creek plant site including its associated asset retirement obligations (AROs) to a nonaffiliated party. I&M paid $92 million and the nonaffiliated party took ownership of the Tanners Creek plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. I&M does not expect to record a gain or loss related to this sale and will address recovery of Tanner’s Creek deferred costs in future rate proceedings. If any of the costs associated with Tanner’s Creek are not recoverable, it could reduce future net income and impact financial condition. 2015 Muskingum River Plant (Generation & Marketing Segment) In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations 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 AROs, 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 statements of operations. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other Segment) 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. 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 International Marine Terminals, LLC, 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. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of operations for the three and nine months ended September 30, 2015 , as shown in the following table: Three Months Ended September 30, Nine Months Ended September 30, 2015 2015 (in millions) Other Revenues $ 129.1 $ 372.2 Other Operation Expense 96.7 273.1 Maintenance Expense 4.2 19.9 Depreciation and Amortization Expense 8.8 26.9 Taxes Other Than Income Taxes 2.7 9.9 Total Expenses 112.4 329.8 Other Income (Expense) (5.4 ) (14.5 ) Pretax Income of Discontinued Operations 11.3 27.9 Income Tax Expense 3.6 9.7 Equity Earnings of Unconsolidated Subsidiaries 0.1 — Total Income on Discontinued Operations as Presented on the Statements of Operations $ 7.8 $ 18.2 In the second quarter of 2016, AEP recorded a $3 million loss related to the final accounting for the sale of AEPRO, which was recorded in Income (Loss) from Discontinued Operations, Net of Tax, on AEP’s statements of operations. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) During the third quarter of 2016, AEP received bids and selected a buyer, received approval from AEP’s Board of Directors and signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,326 MW of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale is subject to regulatory approvals from the FERC, the IURC and federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR). In October 2016, the Federal Trade Commission granted the sale early termination of the HSR waiting period thereby satisfying the HSR conditions to close the transaction. The sale is expected to close in the first quarter of 2017. Upon evaluation, management concluded that the disposal group met the classification as held for sale in the third quarter of 2016. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of September 30, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense and Equity Earnings of the four plants was approximately $116 million and $118 million for the three months ended September 30, 2016 and 2015 , respectively, and $312 million and $404 million for the nine months ended September 30, 2016 and 2015 , respectively. September 30, 2016 Assets: (in millions) Fuel $ 139.7 Materials and Supplies 48.7 Property, Plant and Equipment - Net 1,726.5 Other Class of Assets That Are Not Major 0.4 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,915.3 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 53.1 Asset Retirement Obligations 36.3 Other Classes of Liabilities That Are Not Major 6.8 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 231.0 IMPAIRMENTS 2016 Merchant Generating Assets (Generation & Marketing Segment) In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. Cardinal Unit 1, a 43.5% interest in Conesville Unit 4, Conesville Units 5-6, a 26% interest in Stuart Units 1-4, a 25.4% interest in Zimmer Unit 1, and a 54.7% interest in Oklaunion (collectively the “Merchant Coal-Fired Generation Assets”) were subject to this analysis. Additionally, Racine Hydroelectric Plant (“Racine”), Putnam and I&M’s Price River coal reserves (“Coal Reserves”) and Desert Sky and Trent Wind Farms (“Wind Farms”) were also included in this analysis. For the Merchant Coal-Fired Generation Assets, Racine and the Wind Farms, AEP performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the assets based upon energy and capacity price curves, as applicable, which were developed internally with both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step one analysis concluded the book value of Racine would be recovered and the book value of the remaining assets would not be recovered. AEP performed step two of the impairment analysis on the Merchant Coal-Fired Generation Assets using a ten-year discounted cash flow model based upon forecasted energy and capacity price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The step two analysis resulted in projected negative cash flows. Based on this result, coupled with the significant capital investments necessary to comply with environmental rules to allow the Merchant Coal-Fired Generation Assets to operate to the end of their currently estimated depreciable lives and the joint-ownership structure of these facilities, management determined the fair value of these assets was $0. AEP performed step two of the impairment analysis on the Wind Farms using a ten-year discounted cash flow model utilizing forecasted energy price curves, which were developed internally using both observable Level 2 third party quotations and unobservable Level 3 inputs, as well as management’s forecasts of operating expenses and capital expenditures. The results concluded the Wind Farms were also impaired. For the Coal Reserves, AEP performed step one of the impairment analysis and concluded the book value of the assets would not be recovered. Step two of the impairment analysis on the Coal Reserves was performed using a market approach with Level 3 unobservable inputs. The results concluded the Coal Reserves were also impaired. Based on the impairment analysis performed, in the third quarter of 2016, AEP recorded a pretax impairment of $2.3 billion in Asset Impairments and Other Related Charges on the statement of operations. See the table below for additional information. Impaired Assets Book Value Fair Value Impairment (in millions) Merchant Coal-Fired Generation Assets $ 2,139.4 $ — $ 2,139.4 Trent and Desert Sky Wind Farms 118.7 46.0 72.7 Coal Reserves (a) 56.6 3.8 52.8 Total $ 2,314.7 $ 49.8 $ 2,264.9 (a) Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment.

Benefit Plans

Benefit Plans	9 Months Ended
	Sep. 30, 2016
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )
Appalachian Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )
Indiana Michigan Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )
Ohio Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )
Public Service Co Of Oklahoma [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )
Southwestern Electric Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans for the three and nine months ended September 30, 2016 and 2015 : AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 2016
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Appalachian Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Indiana Michigan Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Ohio Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Public Service Co Of Oklahoma [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Southwestern Electric Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, 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 • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. 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 6 for additional information. The tables below present AEP’s reportable segment income statement information for the three and nine months ended September 30, 2016 and 2015 and reportable segment balance sheet information as of September 30, 2016 and December 31, 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, which has an electricity transmission and distribution business. 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	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c
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 September 30, 2016 and December 31, 2015 : Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2016 and December 31, 2015 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: September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets as of September 30, 2016 and December 31, 2015 : AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (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. APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category 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 September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category 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 three and nine months ended September 30, 2016 and 2015 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (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 are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. The following table shows the results of hedging gains (losses) during the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 ) During the three and nine months ended September 30, 2016 and 2015 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding power derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2016 and 2015 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and nine months ended September 30, 2016 and 2015 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2016 and 2015 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and nine months ended September 30, 2016 and 2015 , 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 September 30, 2016 and December 31, 2015 were: Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of September 30, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 135 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 ) The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of c

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem
Indiana Michigan Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem
Ohio Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem
Southwestern Electric Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrants as of September 30, 2016 and December 31, 2015 are summarized in the following table: September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. 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. The following is a summary of Other Temporary Investments: September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The following is a summary of nuclear trust fund investments as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8 The base cost of fixed income securities was $913 million and $771 million as of September 30, 2016 and December 31, 2015 , respectively. The base cost of equity securities was $588 million and $555 million as of September 30, 2016 and December 31, 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2016 and 2015 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2016 and December 31, 2015 : Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 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 September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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 September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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 September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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 September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs Decem

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.
Appalachian Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.
Indiana Michigan Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.
Ohio Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.
Public Service Co Of Oklahoma [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.
Southwestern Electric Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The 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 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 capital 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 change in the valuation allowance in the third quarter of 2016. AEP reduced the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets as held for sale and the filing of the 2015 federal income tax return. The sale of these assets is expected to result in a gain, the character of which allows AEP to use the capital loss and reverse substantially all of the remaining capital loss valuation allowance previously recorded. A valuation allowance of $9 million has been recorded against AEP’s deferred tax asset balance as of September 30, 2016. The valuation allowance reflects management’s assessment of the amount of deferred tax assets that are more likely than 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. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. AEP was informed that the IRS expects the Joint Committee to refer the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, PSO and SWEPCo) In March 2016, the Texas Comptroller of Public Accounts issued clarifying guidance regarding the treatment of transmission and distribution expenses included in the computation of taxable income for purposes of calculating the Texas gross margin tax. The guidance clarified which specific transmission and distribution expenses are included in the computation of the cost of goods sold deduction. This guidance resulted in a net favorable adjustment to net income of $21 million , $2 million and $9 million during the first nine months of 2016 for AEP, PSO and SWEPCo, respectively. In March 2016, Louisiana enacted several tax bills impacting income taxes, franchise taxes and sales taxes. The income tax provisions limit the use of Louisiana net operating losses and the sales tax provisions increase the sales tax rate and suspend or eliminate certain exemptions. The legislation is not expected to materially impact net income or cash flows.

Financing Activities

Financing Activities	9 Months Ended
	Sep. 30, 2016
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Appalachian Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Indiana Michigan Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Ohio Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Public Service Co Of Oklahoma [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Southwestern Electric Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding as of September 30, 2016 and December 31, 2015 : Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2016 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6 In October 2016, I&M retired $16 million of Notes Payable related to DCC Fuel. As of September 30, 2016 , trustees held, on behalf of AEP, $614 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 September 30, 2016 , 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% . 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.” 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. As of September 30, 2016 , these restrictions did not limit the ability of the subsidiaries to pay dividends out of retained earnings. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2016 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0 The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2016 and December 31, 2015 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the nine months ended September 30, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (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: Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2016 and 2015 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool for the nine months ended September 30, 2016 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 the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 % Short-term Debt (Applies to AEP) Outstanding short-term debt was as follows: September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . 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 and expires in June 2018 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5 September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8 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 September 30, 2016 and December 31, 2015 was as follows: Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2016
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report. The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30, 2016. See “Assets and Liabilities Held For Sale” section of Note 6 for additional information.
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report. The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30, 2016. See “Assets and Liabilities Held For Sale” section of Note 6 for additional information.
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report. The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30, 2016. See “Assets and Liabilities Held For Sale” section of Note 6 for additional information.
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report. The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30, 2016. See “Assets and Liabilities Held For Sale” section of Note 6 for additional information.
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 three months ended September 30, 2016 and 2015 were $42 million and $41 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $127 million and $124 million , respectively. See the tables 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 three months ended September 30, 2016 and 2015 were $23 million and $29 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $77 million and $86 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 tables 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 $1.3 billion and $1.5 billion as of September 30, 2016 and December 31, 2015 , 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 $1.1 billion and $1.3 billion as of September 30, 2016 and December 31, 2015 , 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 $140 million and $185 million as of September 30, 2016 and December 31, 2015 , 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 $68 million and $86 million as of September 30, 2016 and December 31, 2015 , 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 tables 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 $319 million and $342 million as of September 30, 2016 and December 31, 2015 , 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 $311 million and $328 million as of September 30, 2016 and December 31, 2015 , respectively, which are presented separately on the face of the balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding’s securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s balance sheets. AEP Credit 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 “Sale of Receivables - AEP Credit” section of Note 12 . 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 is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the three months ended September 30, 2016 and 2015 was $15 million and $13 million , respectively, and for the nine months ended September 30, 2016 and 2015 was $28 million and $27 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy 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 $38 million and $47 million during the nine months ended September 30, 2016 and the year ended December 31, 2015 , 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 September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 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 three months ended September 30, 2016 and 2015 were $15 million and $30 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $43 million and $59 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: September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2 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 April 2015, PATH filed a stipulation agreement with the FERC that agreed to a 50% debt and 50% equity capital structure and a 4.7% cost of long-term debt for the entire amortization period. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, which if adopted by the FERC, would deem certain costs not recoverable. The Initial Decision has no binding effect. Additional briefing was submitted during the fourth quarter of 2015. The case is currently pending before FERC. Depending on the outcome of this proceeding, PATH-WV may be required to refund certain amounts that have been collected under its formula rate. Management believes its financial statements adequately address the potential impact of this proceeding. AEP’s investment in PATH-WV was: September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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 September 30, 2016 , 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: Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of AEP, 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 three months ended September 30, 2016 and 2015 were $65 million and $67 million , respectively, and for the nine months ended September 30, 2016 and 2015 were $166 million and $182 million , respectively. The carrying amount of I&M’s liabilities associated with AEGCo as of September 30, 2016 and December 31, 2015 was $17 million and $17 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 in the 2015 Annual Report. The assets and liabilities of AEGCo’s Lawrenceburg Plant have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on the balance sheet as of September 30, 2016. See “Assets and Liabilities Held For Sale” section of Note 6 for additional information.

Significant Accounting Matters

Significant Accounting Matters (Policies)	9 Months Ended
	Sep. 30, 2016
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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.
Earnings Per Share	Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
Appalachian Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant. Net income for the three and nine months ended September 30, 2016 is not necessarily indicative of results that may be expected for the year ending December 31, 2016 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2015 financial statements and notes thereto, which are included in the Registrant’s Annual Reports on Form 10-K as filed with the SEC on February 23, 2016 .
Income Taxes and Investment Tax Credits	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	9 Months Ended
	Sep. 30, 2016
Derivatives and Hedging	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of operations. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Fair Value Hedging Strategies (Applies to AEP) Parent enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. 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 would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.
Appalachian Power Co [Member]
Derivatives and Hedging	Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEPEP is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and, 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 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.” Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral.
Indiana Michigan Power Co [Member]
Derivatives and Hedging	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. 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 utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. 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.
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. 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 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. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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 utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. 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 interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	9 Months Ended
	Sep. 30, 2016
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Appalachian Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Indiana Michigan Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Ohio Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Public Service Co Of Oklahoma [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Southwestern Electric Power Co [Member]
Valuation Techniques	Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents, Other Temporary Investments and Restricted Cash for Securitized Funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets and Liabilities Measured on Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	9 Months Ended
	Sep. 30, 2016
Income Tax Policy	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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	Investment Tax Credits Investment tax credits (ITC) were historically accounted for under the flow-through method, except where regulatory commissions reflected ITC in the rate-making process. In the third quarter of 2016, AEP and subsidiaries changed accounting for the recognition of ITC and elected to apply the preferred deferral methodology. Retrospective application is not necessary for reporting periods prior to 2016 as the financial impact to AEP and subsidiaries was immaterial. Deferred ITC is amortized to income tax expense over the life of the asset. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized. 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.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	9 Months Ended
	Sep. 30, 2016
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.

Significant Accounting Matter27

Significant Accounting Matters (Tables)	9 Months Ended
	Sep. 30, 2016
Basic and Diluted EPS Calculations	Three Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income (Loss) from Continuing Operations $ (764.2 ) $ 511.8 Less: Net Income Attributable to Noncontrolling Interests 1.6 1.3 Earnings (Loss) Attributable to AEP Common Shareholders from Continuing Operations $ (765.8 ) $ 510.5 Weighted Average Number of Basic Shares Outstanding 491.7 $ (1.56 ) 490.6 $ 1.04 Weighted Average Dilutive Effect of Restricted Stock Units 0.1 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.8 $ (1.56 ) 490.8 $ 1.04 Nine Months Ended September 30, 2016 2015 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 245.3 $ 1,563.4 Less: Net Income Attributable to Noncontrolling Interests 5.3 4.1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 240.0 $ 1,559.3 Weighted Average Number of Basic Shares Outstanding 491.4 $ 0.49 490.2 $ 3.18 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 491.6 $ 0.49 490.4 $ 3.18

Comprehensive Income (Tables)

Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2016
Changes in Accumulated Other Comprehensive Income by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Pension Total (in millions) Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) Change in Fair Value Recognized in AOCI (26.7 ) — 0.5 — (26.2 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (5.4 ) — — — (5.4 ) Purchased Electricity for Resale 1.8 — — — 1.8 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.0 5.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.6 ) 0.6 — 0.2 (2.8 ) Income Tax (Expense) Credit (1.3 ) 0.2 — — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.2 (1.7 ) Net Current Period Other Comprehensive Income (Loss) (29.0 ) 0.4 0.5 0.2 (27.9 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5.2 ) $ (17.7 ) $ 8.0 $ (87.6 ) $ (102.5 ) Change in Fair Value Recognized in AOCI (3.3 ) 0.3 (1.3 ) — (4.3 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (19.5 ) — — — (19.5 ) Purchased Electricity for Resale 14.3 — — — 14.3 Interest Expense — (0.2 ) — — (0.2 ) Amortization of Prior Service Cost (Credit) — — — (4.8 ) (4.8 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.2 ) (0.2 ) — 0.5 (4.9 ) Income Tax (Expense) Credit (3.0 ) (0.1 ) — 0.2 (2.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.2 ) (0.1 ) — 0.3 (2.0 ) Net Current Period Other Comprehensive Income (Loss) (5.5 ) 0.2 (1.3 ) 0.3 (6.3 ) Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (17.7 ) — 1.7 — (16.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (20.7 ) — — — (20.7 ) Purchased Electricity for Resale 14.2 — — — 14.2 Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 15.2 15.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (6.5 ) 1.7 — 0.6 (4.2 ) Income Tax (Expense) Credit (2.3 ) 0.6 — 0.2 (1.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (4.2 ) 1.1 — 0.4 (2.7 ) Net Current Period Other Comprehensive Income (Loss) (21.9 ) 1.1 1.7 0.4 (18.7 ) Balance in AOCI as of September 30, 2016 $ (27.1 ) $ (16.1 ) $ 8.8 $ (111.4 ) $ (145.8 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ (93.3 ) $ (103.1 ) Change in Fair Value Recognized in AOCI (2.0 ) 0.9 (1.0 ) — (2.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (36.3 ) — — — (36.3 ) Purchased Electricity for Resale 20.4 — — — 20.4 Interest Expense — 1.0 — — 1.0 Amortization of Prior Service Cost (Credit) — — — (14.6 ) (14.6 ) Amortization of Actuarial (Gains)/Losses — — — 16.0 16.0 Reclassifications from AOCI, before Income Tax (Expense) Credit (15.9 ) 1.0 — 1.4 (13.5 ) Income Tax (Expense) Credit (5.6 ) 0.3 — 0.5 (4.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (10.3 ) 0.7 — 0.9 (8.7 ) Net Current Period Other Comprehensive Income (Loss) (12.3 ) 1.6 (1.0 ) 0.9 (10.8 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5.1 5.1 Balance in AOCI as of September 30, 2015 $ (10.7 ) $ (17.5 ) $ 6.7 $ (87.3 ) $ (108.8 )
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) — (0.2 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.7 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Income Tax (Expense) Credit — (0.2 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ 4.0 $ 0.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.2 ) (1.2 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.7 ) (1.0 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.5 ) (0.7 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.5 ) (0.7 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) — (0.8 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 2.2 2.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) (1.6 ) (2.4 ) Income Tax (Expense) Credit (0.2 ) (0.6 ) (0.8 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) (1.0 ) (1.6 ) Net Current Period Other Comprehensive Loss (0.6 ) (1.0 ) (1.6 ) Balance in AOCI as of September 30, 2016 $ 3.0 $ (7.4 ) $ (4.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 3.9 $ 1.1 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.1 ) — (0.1 ) Amortization of Prior Service Cost (Credit) — (3.8 ) (3.8 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (2.1 ) (2.2 ) Income Tax (Expense) Credit — (0.7 ) (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (1.4 ) (1.5 ) Net Current Period Other Comprehensive Loss (0.1 ) (1.4 ) (1.5 ) Balance in AOCI as of September 30, 2015 $ 3.8 $ (0.3 ) $ 3.5
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (13.9 ) $ 0.1 $ (13.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 — 0.4 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.5 — 1.5 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.5 — 1.5 Income Tax (Expense) Credit 0.5 — 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.0 — 1.0 Net Current Period Other Comprehensive Income 1.0 — 1.0 Balance in AOCI as of September 30, 2016 $ (12.3 ) $ (3.4 ) $ (15.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (14.4 ) $ 0.1 $ (14.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.2 — 1.2 Amortization of Prior Service Cost (Credit) — (0.6 ) (0.6 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.2 — 1.2 Income Tax (Expense) Credit 0.4 — 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.8 — 0.8 Net Current Period Other Comprehensive Income 0.8 — 0.8 Balance in AOCI as of September 30, 2015 $ (13.6 ) $ 0.1 $ (13.5 )
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.5 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.5 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.5 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of September 30, 2015 $ 4.6 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.4 ) Income Tax (Expense) Credit (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2016 $ 3.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.6 ) Income Tax (Expense) Credit (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.0 ) Net Current Period Other Comprehensive Loss (1.0 ) Balance in AOCI as of September 30, 2015 $ 4.6
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income by Component	PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2016 $ 3.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of June 30, 2015 $ 4.6 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.2 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) Net Current Period Other Comprehensive Loss (0.1 ) Balance in AOCI as of September 30, 2015 $ 4.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.9 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.6 ) Net Current Period Other Comprehensive Loss (0.6 ) Balance in AOCI as of September 30, 2016 $ 3.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency (in millions) Balance in AOCI as of December 31, 2014 $ 5.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of September 30, 2015 $ 4.5
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income by Component	SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.2 ) 0.5 Income Tax (Expense) Credit 0.3 (0.1 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.1 ) 0.3 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.1 ) 0.3 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (10.0 ) $ 3.1 $ (6.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.7 — 0.7 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.1 0.1 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.7 (0.4 ) 0.3 Income Tax (Expense) Credit 0.3 (0.2 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2016 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.0 — 2.0 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.6 0.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.0 (0.8 ) 1.2 Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.3 (0.5 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.3 (0.5 ) 0.8 Balance in AOCI as of September 30, 2016 $ (7.8 ) $ (0.8 ) $ (8.6 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Interest Rate and Foreign Currency Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ (11.1 ) $ 3.6 $ (7.5 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 2.4 — 2.4 Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 2.4 (1.1 ) 1.3 Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1.5 (0.7 ) 0.8 Net Current Period Other Comprehensive Income (Loss) 1.5 (0.7 ) 0.8 Balance in AOCI as of September 30, 2015 $ (9.6 ) $ 2.9 $ (6.7 )

Rate Matters (Tables)

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2016
Regulatory Assets Pending Final Regulatory Approval	AEP September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 161.3 $ — Storm-Related Costs 25.4 24.2 Plant Retirement Costs - Materials and Supplies 20.8 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.2 — Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 56.7 59.8 Storm-Related Costs 26.7 18.2 Cook Plant Turbine 12.0 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 39.0 22.0 Total Regulatory Assets Pending Final Regulatory Approval $ 343.3 $ 167.9
Appalachian Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	APCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.2 $ 9.3 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 32.7 Peak Demand Reduction/Energy Efficiency - Virginia — 12.7 Amos Plant Transfer Costs - West Virginia — 2.0 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval $ 39.4 $ 57.3
Indiana Michigan Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	I&M September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 11.6 $ 11.6 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana 27.1 27.1 Cook Plant Turbine 12.0 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 7.1 4.2 Rockport Dry Sorbent Injection System - Indiana 5.5 2.8 Stranded Costs on Retired Plant 3.9 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.6 — Total Regulatory Assets Pending Final Regulatory Approval $ 67.8 $ 59.3
Ohio Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	OPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return OVEC Purchased Power 9.1 — gridSMART ® Costs 3.2 1.3 Total Regulatory Assets Pending Final Regulatory Approval $ 12.3 $ 1.3
Public Service Co Of Oklahoma [Member]
Regulatory Assets Pending Final Regulatory Approval	PSO September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 85.9 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Regulatory Assets Currently Not Earning a Return Storm-Related Costs 20.5 12.3 Other Regulatory Assets Pending Final Regulatory Approval 1.3 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 108.2 $ 13.4
Southwestern Electric Power Co [Member]
Regulatory Assets Pending Final Regulatory Approval	SWEPCo September 30, December 31, 2016 2015 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Plant Retirement Costs - Asset Retirement Obligation Costs 0.5 — Other Regulatory Assets Pending Final Regulatory Approval 0.1 — Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.5 1.7 Other Regulatory Assets Pending Final Regulatory Approval 2.2 1.1 Total Regulatory Assets Pending Final Regulatory Approval $ 83.8 $ 5.9

Commitments, Guarantees and C30

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017
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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Appalachian Power Co [Member]
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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Indiana Michigan Power Co [Member]
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 $ 291.4 $ 294.7 March 2017 to July 2017 APCo 104.4 105.6 March 2017 I&M 77.0 77.9 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Ohio Power Co [Member]
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 147.2 October 2016 to September 2017 OPCo 4.2 September 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Public Service Co Of Oklahoma [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Southwestern Electric Power Co [Member]
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in millions) AEP $ 36.8 APCo 5.5 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5

Dispositions, Assets and Liab31

Dispositions, Assets and Liabilities Held for Sale and Impairments (Tables)	9 Months Ended
	Sep. 30, 2016
Impaired Assets [Table Text Block]	Impaired Assets Book Value Fair Value Impairment (in millions) Merchant Coal-Fired Generation Assets $ 2,139.4 $ — $ 2,139.4 Trent and Desert Sky Wind Farms 118.7 46.0 72.7 Coal Reserves (a) 56.6 3.8 52.8 Total $ 2,314.7 $ 49.8 $ 2,264.9 (a) Includes the $11 million book value of I&M’s Price River Coal Reserves which were fully impaired. This $11 million impairment is reflected in the Vertically Integrated Utilities Segment.
Results of Discontinued Operation and Assets and Liabilities Held for Sale	September 30, 2016 Assets: (in millions) Fuel $ 139.7 Materials and Supplies 48.7 Property, Plant and Equipment - Net 1,726.5 Other Class of Assets That Are Not Major 0.4 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,915.3 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 53.1 Asset Retirement Obligations 36.3 Other Classes of Liabilities That Are Not Major 6.8 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 231.0 Three Months Ended September 30, Nine Months Ended September 30, 2015 2015 (in millions) Other Revenues $ 129.1 $ 372.2 Other Operation Expense 96.7 273.1 Maintenance Expense 4.2 19.9 Depreciation and Amortization Expense 8.8 26.9 Taxes Other Than Income Taxes 2.7 9.9 Total Expenses 112.4 329.8 Other Income (Expense) (5.4 ) (14.5 ) Pretax Income of Discontinued Operations 11.3 27.9 Income Tax Expense 3.6 9.7 Equity Earnings of Unconsolidated Subsidiaries 0.1 — Total Income on Discontinued Operations as Presented on the Statements of Operations $ 7.8 $ 18.2

Benefit Plans (Tables)

Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2016
Components of Net Periodic Benefit Cost	AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 21.4 $ 23.4 $ 2.6 $ 3.1 Interest Cost 52.9 51.3 15.3 14.2 Expected Return on Plan Assets (70.1 ) (68.6 ) (26.8 ) (27.7 ) Amortization of Prior Service Cost (Credit) 0.6 0.5 (17.3 ) (17.3 ) Amortization of Net Actuarial Loss 21.0 26.7 7.8 4.7 Net Periodic Benefit Cost (Credit) $ 25.8 $ 33.3 $ (18.4 ) $ (23.0 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 64.3 $ 70.1 $ 7.7 $ 9.2 Interest Cost 158.7 153.9 45.7 42.6 Expected Return on Plan Assets (210.2 ) (206.0 ) (80.3 ) (83.3 ) Amortization of Prior Service Cost (Credit) 1.7 1.7 (51.8 ) (51.8 ) Amortization of Net Actuarial Loss 62.9 80.3 23.5 14.1 Net Periodic Benefit Cost (Credit) $ 77.4 $ 100.0 $ (55.2 ) $ (69.2 )
Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost	APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.1 $ 2.1 $ 0.2 $ 0.3 Interest Cost 6.8 6.7 2.7 2.5 Expected Return on Plan Assets (8.8 ) (8.7 ) (4.3 ) (4.5 ) Amortization of Prior Service Credit — — (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 3.5 1.4 0.9 Net Periodic Benefit Cost (Credit) $ 2.7 $ 3.6 $ (2.5 ) $ (3.3 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.5 $ 0.7 $ 0.9 Interest Cost 20.4 20.1 8.1 7.7 Expected Return on Plan Assets (26.5 ) (26.2 ) (13.0 ) (13.6 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.5 ) (7.5 ) Amortization of Net Actuarial Loss 8.0 10.4 4.1 2.7 Net Periodic Benefit Cost (Credit) $ 8.1 $ 10.9 $ (7.6 ) $ (9.8 )
Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost	I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 3.1 $ 3.3 $ 0.4 $ 0.4 Interest Cost 6.3 6.1 1.7 1.6 Expected Return on Plan Assets (8.4 ) (8.1 ) (3.2 ) (3.3 ) Amortization of Prior Service Credit — — (2.4 ) (2.4 ) Amortization of Net Actuarial Loss 2.5 3.1 0.9 0.5 Net Periodic Benefit Cost (Credit) $ 3.5 $ 4.4 $ (2.6 ) $ (3.2 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 9.2 $ 9.7 $ 1.1 $ 1.2 Interest Cost 19.0 18.3 5.2 4.8 Expected Return on Plan Assets (25.2 ) (24.3 ) (9.6 ) (9.9 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (7.1 ) (7.1 ) Amortization of Net Actuarial Loss 7.4 9.4 2.8 1.5 Net Periodic Benefit Cost (Credit) $ 10.5 $ 13.2 $ (7.6 ) $ (9.5 )
Ohio Power Co [Member]
Components of Net Periodic Benefit Cost	OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.2 $ 0.2 Interest Cost 5.1 5.1 1.8 1.6 Expected Return on Plan Assets (6.9 ) (6.8 ) (3.3 ) (3.4 ) Amortization of Prior Service Credit — — (1.7 ) (1.8 ) Amortization of Net Actuarial Loss 2.1 2.6 0.9 0.6 Net Periodic Benefit Cost (Credit) $ 1.9 $ 2.5 $ (2.1 ) $ (2.8 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.9 $ 5.0 $ 0.6 $ 0.6 Interest Cost 15.4 15.2 5.3 4.8 Expected Return on Plan Assets (20.8 ) (20.6 ) (9.7 ) (10.1 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 6.1 7.9 2.8 1.6 Net Periodic Benefit Cost (Credit) $ 5.7 $ 7.6 $ (6.2 ) $ (8.3 )
Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost	PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 1.5 $ 1.6 $ 0.2 $ 0.2 Interest Cost 2.8 2.7 0.8 0.8 Expected Return on Plan Assets (3.9 ) (3.8 ) (1.5 ) (1.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.1 ) (1.1 ) Amortization of Net Actuarial Loss 1.1 1.5 0.4 0.2 Net Periodic Benefit Cost (Credit) $ 1.6 $ 2.1 $ (1.2 ) $ (1.4 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 4.6 $ 4.8 $ 0.5 $ 0.5 Interest Cost 8.4 8.2 2.4 2.3 Expected Return on Plan Assets (11.6 ) (11.4 ) (4.5 ) (4.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.2 ) (3.2 ) Amortization of Net Actuarial Loss 3.3 4.3 1.3 0.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 6.1 $ (3.5 ) $ (4.4 )
Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost	SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 2.0 $ 2.2 $ 0.2 $ 0.2 Interest Cost 3.1 2.9 0.9 0.8 Expected Return on Plan Assets (4.0 ) (4.0 ) (1.7 ) (1.7 ) Amortization of Prior Service Credit — — (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.5 0.5 0.3 Net Periodic Benefit Cost (Credit) $ 2.3 $ 2.6 $ (1.4 ) $ (1.7 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Service Cost $ 6.1 $ 6.3 $ 0.6 $ 0.6 Interest Cost 9.3 8.8 2.7 2.5 Expected Return on Plan Assets (12.3 ) (12.0 ) (5.0 ) (5.2 ) Amortization of Prior Service Cost (Credit) 0.2 0.2 (3.9 ) (3.8 ) Amortization of Net Actuarial Loss 3.6 4.5 1.5 0.8 Net Periodic Benefit Cost (Credit) $ 6.9 $ 7.8 $ (4.1 ) $ (5.1 )

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2016 Revenues from: External Customers $ 2,538.3 $ 1,245.4 $ 39.5 $ 823.3 $ 5.7 $ — $ 4,652.2 Other Operating Segments 18.0 30.2 92.9 36.1 19.1 (196.3 ) — Total Revenues $ 2,556.3 $ 1,275.6 $ 132.4 $ 859.4 $ 24.8 $ (196.3 ) $ 4,652.2 Income (Loss) from Continuing Operations $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 343.4 $ 155.5 $ 69.5 $ (1,369.2 ) $ 36.6 $ — $ (764.2 ) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,435.8 $ 1,163.6 $ 26.9 $ 801.8 $ 3.3 $ — $ 4,431.4 Other Operating Segments 35.7 25.0 60.6 34.2 20.5 (176.0 ) — Total Revenues $ 2,471.5 $ 1,188.6 $ 87.5 $ 836.0 $ 23.8 $ (176.0 ) $ 4,431.4 Income (Loss) from Continuing Operations $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (13.2 ) $ — $ 511.8 Income from Discontinued Operations, Net of Tax — — — — 7.8 — 7.8 Net Income (Loss) $ 274.5 $ 113.0 $ 45.9 $ 91.6 $ (5.4 ) $ — $ 519.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2016 Revenues from: External Customers $ 6,864.6 $ 3,398.9 $ 110.1 $ 2,192.5 $ 23.9 $ — $ 12,590.0 Other Operating Segments 63.2 69.6 272.6 98.7 55.2 (559.3 ) — Total Revenues $ 6,927.8 $ 3,468.5 $ 382.7 $ 2,291.2 $ 79.1 $ (559.3 ) $ 12,590.0 Income (Loss) from Continuing Operations $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 63.9 $ — $ 245.3 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 832.6 $ 388.1 $ 209.5 $ (1,248.8 ) $ 61.4 $ — $ 242.8 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended September 30, 2015 Revenues from: External Customers $ 7,081.8 $ 3,377.9 $ 74.1 $ 2,288.6 $ 16.1 $ — $ 12,838.5 Other Operating Segments 77.3 141.5 170.8 518.1 57.8 (965.5 ) — Total Revenues $ 7,159.1 $ 3,519.4 $ 244.9 $ 2,806.7 $ 73.9 $ (965.5 ) $ 12,838.5 Income (Loss) from Continuing Operations $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ (15.1 ) $ — $ 1,563.4 Income from Discontinued Operations, Net of Tax — — — — 18.2 — 18.2 Net Income $ 782.7 $ 287.8 $ 147.7 $ 360.3 $ 3.1 $ — $ 1,581.6 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) September 30, 2016 Total Property, Plant and Equipment $ 41,015.6 $ 14,438.4 $ 4,896.4 $ 234.3 $ 368.6 $ (353.5 ) (b) $ 60,599.8 Accumulated Depreciation and Amortization 12,549.8 3,647.4 88.2 44.2 192.1 (184.1 ) (b) 16,337.6 Total Property Plant and Equipment - Net $ 28,465.8 $ 10,791.0 $ 4,808.2 $ 190.1 $ 176.5 $ (169.4 ) (b) $ 44,262.2 Assets Held for Sale $ — $ — $ — $ 1,915.3 $ — $ — $ 1,915.3 Total Assets $ 36,924.3 $ 14,155.7 $ 5,780.5 $ 3,176.6 $ 21,772.4 $ (20,367.5 ) (b) (c) $ 61,442.0 Long-term Debt Due Within One Year: Non-Affiliated $ 1,611.0 $ 268.3 $ — $ 505.2 $ 0.3 $ — $ 2,384.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,067.3 4,745.3 1,660.4 — 846.9 — 17,319.9 Total Long-term Debt $ 11,698.3 $ 5,013.6 $ 1,660.4 $ 537.4 $ 847.2 $ (52.2 ) $ 19,704.7 Liabilities Held for Sale $ — $ — $ — $ 231.0 $ — $ — $ 231.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2015 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (b) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (b) 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 ) (b) $ 46,133.2 Total Assets $ 35,792.3 $ 14,640.2 $ 5,012.1 $ 5,414.5 $ 21,907.4 $ (21,083.4 ) (b) (c) $ 61,683.1 Long-term Debt Due Within One Year: 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 (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 eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	9 Months Ended
	Sep. 30, 2016
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments September 30, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 267.0 $ 8.0 $ 0.3 $ 275.3 $ (164.5 ) $ 110.8 Long-term Risk Management Assets 364.2 5.4 — 369.6 (57.9 ) 311.7 Total Assets 631.2 13.4 0.3 644.9 (222.4 ) 422.5 Current Risk Management Liabilities 241.5 6.6 0.2 248.3 (169.0 ) 79.3 Long-term Risk Management Liabilities 273.3 48.7 0.3 322.3 (82.3 ) 240.0 Total Liabilities 514.8 55.3 0.5 570.6 (251.3 ) 319.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 116.4 $ (41.9 ) $ (0.2 ) $ 74.3 $ 28.9 $ 103.2 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (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 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Gain (Loss) on Hedging Instruments	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ (1.1 ) $ 3.7 $ 3.0 $ 6.8 Gain (Loss) on Fair Value Portion of Long-term Debt 1.1 (3.7 ) (3.0 ) (6.8 )
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on AEP’s Balance Sheets September 30, 2016 December 31, 2015 Interest Rate Interest Rate and Foreign and Foreign Commodity Currency Commodity Currency (in millions) Hedging Assets (a) $ 6.5 $ — $ 17.6 $ — Hedging Liabilities (a) 48.4 0.2 26.1 0.4 AOCI Gain (Loss) Net of Tax (27.1 ) (16.1 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 0.9 (1.2 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
Collateral Required Under Various Triggering Events	September 30, 2016 December 31, 2015 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable to Other to Post Attributable to Other Company RTOs and ISOs Contracts RTOs and ISOs Contracts (in millions) AEP $ 23.9 $ 292.4 (a) $ 17.5 $ 297.8 (a) APCo 4.4 — 4.9 0.1 I&M 2.7 — 3.3 0.1 PSO 3.9 3.2 — 3.2 SWEPCo 4.7 0.1 — 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	September 30, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.8 $ 10.6 $ 253.8 APCo 1.3 — 1.3 I&M 0.8 — 0.8 December 31, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Appalachian Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 11.0 $ (7.8 ) $ 3.2 Long-term Risk Management Assets - Nonaffiliated 1.0 (0.8 ) 0.2 Total Assets 12.0 (8.6 ) 3.4 Current Risk Management Liabilities - Nonaffiliated 18.5 (7.8 ) 10.7 Long-term Risk Management Liabilities - Nonaffiliated 1.1 (0.8 ) 0.3 Total Liabilities 19.6 (8.6 ) 11.0 Total MTM Derivative Contract Net Liabilities $ (7.6 ) $ — $ (7.6 ) APCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 25.9 $ (10.3 ) $ 15.6 Long-term Risk Management Assets - Nonaffiliated 0.3 (0.2 ) 0.1 Total Assets 26.2 (10.5 ) 15.7 Current Risk Management Liabilities - Nonaffiliated 18.1 (13.3 ) 4.8 Long-term Risk Management Liabilities - Nonaffiliated 0.3 (0.2 ) 0.1 Total Liabilities 18.4 (13.5 ) 4.9 Total MTM Derivative Contract Net Assets $ 7.8 $ 3.0 $ 10.8 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	September 30, 2016 December 31, 2015 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable to Other to Post Attributable to Other Company RTOs and ISOs Contracts RTOs and ISOs Contracts (in millions) AEP $ 23.9 $ 292.4 (a) $ 17.5 $ 297.8 (a) APCo 4.4 — 4.9 0.1 I&M 2.7 — 3.3 0.1 PSO 3.9 3.2 — 3.2 SWEPCo 4.7 0.1 — 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	September 30, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.8 $ 10.6 $ 253.8 APCo 1.3 — 1.3 I&M 0.8 — 0.8 December 31, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Indiana Michigan Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	I&M Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated $ 10.8 $ (5.6 ) $ 5.2 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.4 ) 0.2 Total Assets 11.4 (6.0 ) 5.4 Current Risk Management Liabilities - Nonaffiliated 7.2 (5.9 ) 1.3 Long-term Risk Management Liabilities - Nonaffiliated 0.6 (0.4 ) 0.2 Total Liabilities 7.8 (6.3 ) 1.5 Total MTM Derivative Contract Net Assets $ 3.6 $ 0.3 $ 3.9 I&M Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets - Nonaffiliated and Affiliated $ 22.8 $ (10.5 ) $ 12.3 Long-term Risk Management Assets - Nonaffiliated 0.6 (0.6 ) — Total Assets 23.4 (11.1 ) 12.3 Current Risk Management Liabilities - Nonaffiliated 17.0 (10.7 ) 6.3 Long-term Risk Management Liabilities - Nonaffiliated 2.6 (1.0 ) 1.6 Total Liabilities 19.6 (11.7 ) 7.9 Total MTM Derivative Contract Net Assets $ 3.8 $ 0.6 $ 4.4 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	September 30, 2016 December 31, 2015 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable to Other to Post Attributable to Other Company RTOs and ISOs Contracts RTOs and ISOs Contracts (in millions) AEP $ 23.9 $ 292.4 (a) $ 17.5 $ 297.8 (a) APCo 4.4 — 4.9 0.1 I&M 2.7 — 3.3 0.1 PSO 3.9 3.2 — 3.2 SWEPCo 4.7 0.1 — 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Liabilities Subject to Cross Default Provisions	September 30, 2016 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 285.8 $ 10.6 $ 253.8 APCo 1.3 — 1.3 I&M 0.8 — 0.8 December 31, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Ohio Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.1 $ (0.1 ) $ — Long-term Risk Management Assets — — — Total Assets 0.1 (0.1 ) — Current Risk Management Liabilities 5.7 (0.1 ) 5.6 Long-term Risk Management Liabilities 103.5 — 103.5 Total Liabilities 109.2 (0.1 ) 109.1 Total MTM Derivative Contract Net Liabilities $ (109.1 ) $ — $ (109.1 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets 19.2 — 19.2 Total Assets 19.2 — 19.2 Current Risk Management Liabilities 4.1 (0.5 ) 3.6 Long-term Risk Management Liabilities — — — Total Liabilities 4.1 (0.5 ) 3.6 Total MTM Derivative Contract Net Assets $ 15.1 $ 0.5 $ 15.6 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 )
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.2 $ (0.1 ) $ 1.1 Long-term Risk Management Assets — — — Total Assets 1.2 (0.1 ) 1.1 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.1 $ — $ 1.1 PSO Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (0.3 ) 0.2 Long-term Risk Management Liabilities — — — Total Liabilities 0.5 (0.3 ) 0.2 Total MTM Derivative Contract Net Assets $ 0.1 $ 0.3 $ 0.4 (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	September 30, 2016 December 31, 2015 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable to Other to Post Attributable to Other Company RTOs and ISOs Contracts RTOs and ISOs Contracts (in millions) AEP $ 23.9 $ 292.4 (a) $ 17.5 $ 297.8 (a) APCo 4.4 — 4.9 0.1 I&M 2.7 — 3.3 0.1 PSO 3.9 3.2 — 3.2 SWEPCo 4.7 0.1 — 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments September 30, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 398.7 66.4 22.4 11.3 18.3 21.8 Coal Tons 2.1 — 0.7 — — 1.4 Natural Gas MMBtus 37.3 — — — — — Heating Oil and Gasoline Gallons 6.9 1.3 0.6 1.5 0.8 0.9 Interest Rate USD $ 82.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 505.2 $ — $ — $ — $ — $ — 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 $ — $ — $ — $ — $ —
Cash Collateral Netting	September 30, 2016 December 31, 2015 Cash Collateral Cash Collateral Cash Collateral Cash Collateral Received Paid Received Paid Netted Against Netted Against Netted Against Netted Against Risk Management Risk Management Risk Management Risk Management Company Assets Liabilities Assets Liabilities (in millions) AEP $ 7.1 $ 36.0 $ 5.8 $ 44.4 APCo 0.1 0.1 — 3.1 I&M — 0.3 — 0.6 OPCo — — — 0.5 PSO — — — 0.3 SWEPCo — — — 0.3
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments September 30, 2016 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 1.5 $ (0.1 ) $ 1.4 Long-term Risk Management Assets — — — Total Assets 1.5 (0.1 ) 1.4 Current Risk Management Liabilities 0.1 (0.1 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.1 (0.1 ) — Total MTM Derivative Contract Net Assets $ 1.4 $ — $ 1.4 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Gross Net Amounts of Amounts Assets/Liabilities Risk Offset in the Presented in the Management Statement of Statement of Contracts - Financial Financial Balance Sheet Location Commodity (a) Position (b) Position (c) (in millions) Current Risk Management Assets $ 0.8 $ — $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.8 — 0.8 Current Risk Management Liabilities 3.4 (0.3 ) 3.1 Long-term Risk Management Liabilities 2.1 — 2.1 Total Liabilities 5.5 (0.3 ) 5.2 Total MTM Derivative Contract Net Assets (Liabilities) $ (4.7 ) $ 0.3 $ (4.4 ) (a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 2.4 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 9.2 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.0 1.2 0.1 — (0.1 ) Purchased Electricity for Resale 1.5 0.8 0.1 — — — Other Operation Expense (0.4 ) — — (0.1 ) — — Maintenance Expense (0.4 ) (0.1 ) — (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) (22.5 ) 5.2 1.6 (95.4 ) 0.1 2.8 Regulatory Liabilities (a) 28.6 16.9 5.5 — 0.8 3.7 Total Gain (Loss) on Risk Management Contracts $ 18.5 $ 23.8 $ 8.4 $ (95.5 ) $ 0.8 $ 6.3 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Transmission and Distribution Utilities Revenues $ (0.9 ) $ — $ — $ — $ — $ — Generation & Marketing Revenues 1.0 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.4 ) 0.4 (0.9 ) — — Sales to AEP Affiliates — 1.2 3.3 — — — Purchased Electricity for Resale 1.6 0.8 — — — — Other Operation Expense (0.7 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Maintenance Expense (0.8 ) (0.2 ) (0.1 ) (0.1 ) (0.1 ) (0.1 ) Regulatory Assets (a) 0.1 0.9 (1.0 ) — (0.2 ) 0.2 Regulatory Liabilities (a) (20.3 ) 3.2 (1.7 ) (22.3 ) (0.5 ) 1.1 Total Gain (Loss) on Risk Management Contracts $ (20.0 ) $ 5.4 $ 0.8 $ (23.4 ) $ (0.9 ) $ 1.1 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 3.1 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 50.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.8 ) 3.7 0.1 — (0.1 ) Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 4.9 2.7 0.2 — — — Other Operation Expense (1.3 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.2 ) Maintenance Expense (1.6 ) (0.3 ) (0.1 ) (0.3 ) (0.2 ) (0.2 ) Regulatory Assets (a) (51.0 ) (7.2 ) 3.0 (115.9 ) 0.4 5.5 Regulatory Liabilities (a) 58.0 39.2 11.2 (15.2 ) 3.2 14.7 Total Gain (Loss) on Risk Management Contracts $ 62.3 $ 35.6 $ 23.7 $ (131.6 ) $ 3.3 $ 19.7 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 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 (0.9 ) — — — — — Generation & Marketing Revenues 59.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.8 3.6 (0.9 ) — — Sales to AEP Affiliates — 1.5 4.3 — — — Purchased Electricity for Resale 5.3 1.6 0.3 — — — Other Operation Expense (2.3 ) (0.3 ) (0.2 ) (0.4 ) (0.3 ) (0.4 ) Maintenance Expense (2.2 ) (0.5 ) (0.2 ) (0.4 ) (0.2 ) (0.3 ) Regulatory Assets (a) 0.2 2.1 (1.2 ) — 0.6 (1.2 ) Regulatory Liabilities (a) 33.3 31.8 4.1 (24.8 ) 5.1 14.5 Total Gain (Loss) on Risk Management Contracts $ 100.0 $ 37.0 $ 10.7 $ (26.5 ) $ 5.2 $ 12.6 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets September 30, 2016 December 31, 2015 Interest Rate and Foreign Currency Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 3.0 $ 0.7 $ 3.6 $ 0.7 I&M (12.3 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.3 1.1 4.3 1.2 PSO 3.6 0.8 4.2 0.8 SWEPCo (7.8 ) (1.5 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	September 30, 2016 December 31, 2015 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable to Other to Post Attributable to Other Company RTOs and ISOs Contracts RTOs and ISOs Contracts (in millions) AEP $ 23.9 $ 292.4 (a) $ 17.5 $ 297.8 (a) APCo 4.4 — 4.9 0.1 I&M 2.7 — 3.3 0.1 PSO 3.9 3.2 — 3.2 SWEPCo 4.7 0.1 — 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
Book Values and Fair Values of Long-term Debt	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Other Temporary Investments	September 30, 2016 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 159.2 $ — $ — $ 159.2 Fixed Income Securities – Mutual Funds (b) 92.3 0.3 — 92.6 Equity Securities – Mutual Funds 14.2 13.2 — 27.4 Total Other Temporary Investments $ 265.7 $ 13.5 $ — $ 279.2 December 31, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (b) 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 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
Debt and Equity Securities Within Other Temporary Investments	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.6 9.5 1.6 10.3 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — —
Nuclear Trust Fund Investments	September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ 5.3 $ — $ 194.1 $ 212.2 Other Temporary Investments Restricted Cash (a) 146.7 5.7 — 6.8 159.2 Fixed Income Securities – Mutual Funds 92.6 — — — 92.6 Equity Securities – Mutual Funds (b) 27.4 — — — 27.4 Total Other Temporary Investments 266.7 5.7 — 6.8 279.2 Risk Management Assets Risk Management Commodity Contracts (c) (d) 5.3 399.3 214.7 (203.7 ) 415.6 Cash Flow Hedges: Commodity Hedges (c) — 10.5 1.1 (5.0 ) 6.6 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Assets 5.3 409.8 215.8 (208.4 ) 422.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities – Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,523.5 $ 1,396.4 $ 215.8 $ 9.0 $ 3,144.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 10.0 $ 394.2 $ 98.7 $ (232.6 ) $ 270.3 Cash Flow Hedges: Commodity Hedges (c) — 34.8 18.7 (5.0 ) 48.5 Interest Rate/Foreign Currency Hedges — 0.2 — — 0.2 Fair Value Hedges — — — 0.3 0.3 Total Risk Management Liabilities $ 10.0 $ 429.2 $ 117.4 $ (237.3 ) $ 319.3 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) (f) 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) (f) $ 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
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 207.5 $ 103.7 Discounted Cash Flow Forward Market Price (a) $ 10.19 $ 143.84 $ 43.20 Counterparty Credit Risk (b) 40 840 424 FTRs 8.3 13.7 Discounted Cash Flow Forward Market Price (a) $ (9.89 ) $ 10.63 $ 0.73 Total $ 215.8 $ 117.4 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 (c) 670 FTRs 8.4 3.5 Discounted Cash Flow Forward Market Price (a) $ (6.99 ) $ 10.34 $ 1.10 Total $ 220.7 $ 73.8 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents 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	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 7.8 $ — $ — $ 0.1 $ 7.9 Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) — 8.3 2.8 (7.7 ) 3.4 Total Assets $ 7.8 $ 8.3 $ 2.8 $ (7.6 ) $ 11.3 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 8.8 $ 9.9 $ (7.7 ) $ 11.0 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs September 30, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 2.1 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 0.7 9.7 Discounted Cash Flow Forward Market Price (0.99 ) 10.63 1.94 Total $ 2.8 $ 9.9 Significant Unobservable Inputs December 31, 2015 APCo Significant Input/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
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Nuclear Trust Fund Investments	September 30, 2016 December 31, 2015 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 35.2 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 892.7 55.5 (2.1 ) 731.1 35.9 (2.6 ) Corporate Debt 66.5 6.1 (1.0 ) 57.9 3.2 (1.1 ) State and Local Government 16.4 1.2 (0.3 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 975.6 62.8 (3.4 ) 811.2 40.2 (4.0 ) Equity Securities - Domestic 1,220.0 631.6 (78.0 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,230.8 $ 694.4 $ (81.4 ) $ 2,106.4 $ 611.8 $ (83.3 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in millions) Proceeds from Investment Sales $ 650.0 $ 921.5 $ 2,427.0 $ 1,437.3 Purchases of Investments 656.5 938.4 2,452.9 1,479.1 Gross Realized Gains on Investment Sales 13.9 15.0 41.9 33.8 Gross Realized Losses on Investment Sales 6.5 13.1 22.2 22.8
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 330.4 1 year – 5 years 317.3 5 years – 10 years 150.4 After 10 years 177.5 Total $ 975.6
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 6.6 $ 4.7 $ (5.9 ) $ 5.4 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 18.7 — — 16.5 35.2 Fixed Income Securities: United States Government — 892.7 — — 892.7 Corporate Debt — 66.5 — — 66.5 State and Local Government — 16.4 — — 16.4 Subtotal Fixed Income Securities — 975.6 — — 975.6 Equity Securities - Domestic (b) 1,220.0 — — — 1,220.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,238.7 975.6 — 16.5 2,230.8 Total Assets $ 1,238.7 $ 982.2 $ 4.7 $ 10.6 $ 2,236.2 Liabilities: Risk Management Liabilities - Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 7.5 $ 0.2 $ (6.2 ) $ 1.5 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
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs September 30, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 1.6 $ 0.2 Discounted Cash Flow Forward Market Price $ 16.51 $ 47.42 $ 34.85 FTRs 3.1 — Discounted Cash Flow Forward Market Price (9.89 ) 10.63 1.10 Total $ 4.7 $ 0.2 Significant Unobservable Inputs December 31, 2015 I&M Significant Input/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
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 16.1 $ — $ — $ 0.1 $ 16.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 — (0.1 ) — Total Assets $ 16.1 $ 0.1 $ — $ — $ 16.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 109.1 $ (0.1 ) $ 109.1 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
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs September 30, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 109.1 Discounted Cash Flow Forward Market Price (a) $ 24.38 $ 78.45 $ 52.45 Counterparty Credit Risk (b) 40 323 246 Total $ — $ 109.1 Significant Unobservable Inputs December 31, 2015 OPCo Significant Input/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
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 1.2 $ (0.2 ) $ 1.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 0.1 $ (0.2 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs September 30, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.2 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs December 31, 2015 PSO Significant Input/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
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	September 30, 2016 December 31, 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,839.5 (a) $ 22,840.4 $ 19,572.7 $ 21,201.3 APCo 4,033.1 4,941.8 3,930.7 4,416.7 I&M 2,407.4 2,717.8 2,000.0 2,193.6 OPCo 1,763.4 2,213.4 2,157.7 2,472.7 PSO 1,286.2 1,502.6 1,286.1 1,402.9 SWEPCo 2,674.0 2,943.4 2,273.5 2,417.2 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12.8 $ — $ — $ 2.4 $ 15.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.1 1.4 (0.1 ) 1.4 Total Assets $ 12.8 $ 0.1 $ 1.4 $ 2.3 $ 16.6 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.1 $ (0.1 ) $ — 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 (a) Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other’’ column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.’’ (d) The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 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, 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. (g) Substantially comprised of power contracts for the Registrant Subsidiaries.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 34.2 22.7 3.8 (0.1 ) 0.4 4.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 12.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (34.4 ) — — — — — Purchases, Issuances and Settlements (d) (37.1 ) (17.9 ) (5.0 ) 0.9 (0.7 ) (4.4 ) Transfers into Level 3 (e) (f) 13.1 0.1 — — — — Transfers out of Level 3 (f) (g) (10.0 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (29.0 ) 0.9 2.2 (95.3 ) 0.3 0.3 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Three Months Ended September 30, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of June 30, 2015 $ 203.1 $ 33.8 $ 11.8 $ 37.7 $ 1.7 $ 2.0 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 11.1 5.1 0.9 — (0.3 ) 2.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 6.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2.1 ) — — — — — Purchases, Issuances and Settlements (d) (28.9 ) (14.0 ) (3.6 ) 0.3 (0.2 ) (2.9 ) Transfers into Level 3 (e) (f) 7.8 — — — — — Transfers out of Level 3 (f) (g) (5.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (25.0 ) (1.8 ) (2.7 ) (22.3 ) (0.2 ) (0.2 ) Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 Nine Months Ended September 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.1 25.5 7.0 (1.8 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 45.5 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (16.7 ) — — — — — Purchases, Issuances and Settlements (d) (67.1 ) (36.2 ) (10.3 ) 4.0 0.4 (8.4 ) Transfers into Level 3 (e) (f) 11.2 — — — — — Transfers out of Level 3 (f) (g) 1.1 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) (64.6 ) (8.2 ) 3.4 (127.2 ) 1.1 1.2 Balance as of September 30, 2016 $ 98.4 $ (7.1 ) $ 4.5 $ (109.1 ) $ 1.1 $ 1.3 Nine Months Ended September 30, 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) 13.6 1.7 (0.2 ) 1.2 (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) 54.3 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3.8 ) — — — — — Purchases, Issuances and Settlements (d) (60.2 ) (16.1 ) (12.8 ) (7.9 ) 0.5 (8.7 ) Transfers into Level 3 (e) (f) 28.3 — — — — — Transfers out of Level 3 (f) (g) (17.1 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 0.9 20.5 3.9 (26.0 ) 1.0 1.3 Balance as of September 30, 2015 $ 166.8 $ 23.1 $ 6.4 $ 15.7 $ 1.0 $ 1.3 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the purchases, issuances and settlements 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 liabilities/assets.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs September 30, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 1.4 $ 0.1 Discounted Cash Flow Forward Market Price $ (8.33 ) $ 1.02 $ (0.39 ) Significant Unobservable Inputs December 31, 2015 SWEPCo Significant Input/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 (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents 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)

Financing Activities (Tables)

Financing Activities (Tables)	9 Months Ended
	Sep. 30, 2016
Long-term Debt	Type of Debt September 30, 2016 December 31, 2015 (in millions) Senior Unsecured Notes $ 14,073.9 (a) $ 13,629.1 Pollution Control Bonds 1,724.5 1,784.8 Notes Payable 268.5 264.7 Securitization Bonds 1,737.6 2,024.0 Spent Nuclear Fuel Obligation (b) 266.1 265.6 Other Long-term Debt 1,768.9 1,604.5 Total Long-term Debt Outstanding 19,839.5 (a) 19,572.7 Long-term Debt Due Within One Year 2,519.6 (a) 1,831.8 Long-term Debt $ 17,319.9 $ 17,740.9 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Short Term Debt	September 30, 2016 December 31, 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750.0 0.65 % $ 675.0 0.30 % Commercial Paper 728.3 0.90 % 125.0 0.81 % Total Short-term Debt $ 1,478.3 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
Comparative Accounts Receivable Information	Three Months Ended Nine Months Ended 2016 2015 2016 2015 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.73 % 0.30 % 0.65 % 0.28 % Net Uncollectible Accounts Receivable Written Off $ 7.7 $ 13.5 $ 17.5 $ 27.5
Customer Accounts Receivable Managed Portfolio	September 30, 2016 December 31, 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 1,037.7 $ 924.8 Total Principal Outstanding 750.0 675.0 Delinquent Securitized Accounts Receivable 47.7 48.3 Bad Debt Reserves Related to Securitization of Accounts Receivable 27.8 17.5 Unbilled Receivables Related to Securitization of Accounts Receivable 297.1 357.8
Appalachian Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Indiana Michigan Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Ohio Power Co [Member]
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Public Service Co Of Oklahoma [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3
Southwestern Electric Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Other Long-term Debt $ 125.0 Variable 2019 APCo Pollution Control Bonds 125.3 Variable 2016 APCo Pollution Control Bonds 65.4 1.70 2020 I&M Notes Payable 87.9 Variable 2020 I&M Senior Unsecured Notes 400.0 4.55 2046 PSO Senior Unsecured Notes 50.0 3.05 2026 PSO Senior Unsecured Notes 100.0 4.11 2046 SWEPCo Other Long-term Debt 5.2 3.50 2023 SWEPCo Senior Unsecured Notes 400.0 2.75 2026 Non-Registrant: TCC Other Long-term Debt 125.0 Variable 2019 TNC Other Long-term Debt 75.0 Variable 2019 Transource Missouri Other Long-term Debt 11.5 Variable 2018 Total Issuances $ 1,570.3 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Pollution Control Bonds $ 125.3 Variable 2016 APCo Pollution Control Bonds 65.3 2.25 2016 APCo Securitization Bonds 23.0 2.008 2024 I&M Notes Payable 0.8 Variable 2016 I&M Notes Payable 0.5 2.12 2016 I&M Notes Payable 12.6 Variable 2017 I&M Notes Payable 24.8 Variable 2019 I&M Notes Payable 31.0 Variable 2019 I&M Notes Payable 6.1 Variable 2020 I&M Other Long-term Debt 1.0 6.00 2025 OPCo Other Long-term Debt 0.1 1.149 2028 OPCo Securitization Bonds 45.8 0.958 2018 OPCo Senior Unsecured Notes 350.0 6.00 2016 PSO Other Long-term Debt 0.3 3.00 2027 PSO Senior Unsecured Notes 150.0 6.15 2016 SWEPCo Notes Payable 3.3 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 7.3 6.33 2037 AEP Subsidiaries Notes Payable 5.1 Variable 2017 AEP Subsidiaries Notes Payable 0.1 5.75 2021 AGR Pollution Control Bonds 60.0 Variable 2016 TCC Other Long-term Debt 100.0 Variable 2016 TCC Securitization Bonds 44.2 6.25 2016 TCC Securitization Bonds 149.1 5.17 2018 TCC Securitization Bonds 26.9 0.88 2017 TNC Other Long-term Debt 75.0 Variable 2016 Total Retirements and Principal Payments $ 1,307.6
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 165.5 $ 24.9 $ (59.7 ) $ 600.0 I&M 369.1 97.6 118.9 21.8 (13.9 ) 500.0 OPCo 227.9 379.2 137.8 251.1 0.2 400.0 PSO 9.6 205.4 5.1 47.0 51.1 300.0 SWEPCo 249.4 308.2 171.8 302.8 297.4 350.0
Nonutility Money Pool Activity	Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool September 30, 2016 (in millions) $ 2.0 $ 2.0 $ 2.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Nine Months Ended September 30, 2016 2015 Maximum Interest Rate 0.91 % 0.59 % Minimum Interest Rate 0.69 % 0.39 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 APCo 0.78 % 0.46 % 0.79 % 0.46 % I&M 0.73 % 0.47 % 0.78 % 0.46 % OPCo 0.85 % — % 0.74 % 0.47 % PSO 0.76 % 0.49 % 0.81 % 0.46 % SWEPCo 0.79 % 0.46 % 0.91 % 0.48 %
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool	Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to the Nonutility the Nonutility the Nonutility Money Pool Money Pool Money Pool 0.91 % 0.69 % 0.79 %
Accounts Receivable and Accrued Unbilled Revenues	Company September 30, 2016 December 31, 2015 (in millions) APCo $ 131.9 $ 135.4 I&M 152.5 134.8 OPCo 407.1 351.4 PSO 146.1 116.1 SWEPCo 170.0 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 1.6 $ 2.0 $ 5.4 $ 6.0 I&M 2.0 2.2 5.6 6.6 OPCo 8.1 8.5 23.4 23.2 PSO 1.8 1.7 4.7 4.5 SWEPCo 2.1 2.0 5.3 5.3
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 361.7 $ 355.3 $ 1,071.6 $ 1,115.5 I&M 448.0 401.5 1,220.2 1,192.1 OPCo 750.9 670.7 2,011.2 1,949.0 PSO 390.6 411.5 971.9 1,025.9 SWEPCo 460.4 468.0 1,183.9 1,222.3

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2016
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 million .
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 million .
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6
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	September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 million .
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 million .
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6
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	September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended September 30, Nine Months Ended September 30, Company 2016 2015 2016 2015 (in millions) APCo $ 55.3 $ 63.7 $ 165.7 $ 164.7 I&M 32.7 37.5 97.7 102.1 OPCo 39.4 48.5 123.2 128.6 PSO 23.6 29.9 77.1 77.8 SWEPCo 31.4 39.2 101.2 102.6
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	September 30, 2016 December 31, 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 20.0 $ 20.0 $ 25.8 $ 25.8 I&M 11.0 11.0 16.6 16.6 OPCo 13.9 13.9 23.3 23.3 PSO 7.8 7.8 12.6 12.6 SWEPCo 11.8 11.8 16.4 16.4
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2016 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 $ 61.8 $ 109.2 $ 18.9 $ 11.8 $ 1,038.7 $ 163.5 $ 179.4 $ 12.2 Net Property, Plant and Equipment 123.6 165.9 — — — — — 298.5 Other Noncurrent Assets 63.9 78.8 128.1 (a) 314.7 (b) 10.3 1,210.4 (c) 1.7 5.5 Total Assets $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 LIABILITIES AND EQUITY Current Liabilities $ 32.0 $ 98.2 $ 46.9 $ 25.0 $ 948.2 $ 242.6 $ 47.7 $ 35.4 Noncurrent Liabilities 217.0 255.7 98.8 300.2 0.6 1,113.2 91.1 127.2 Equity 0.3 — 1.3 1.3 100.2 18.1 42.3 153.6 Total Liabilities and Equity $ 249.3 $ 353.9 $ 147.0 $ 326.5 $ 1,049.0 $ 1,373.9 $ 181.1 $ 316.2 (a) Includes an intercompany item eliminated in consolidation of $60.2 million . (b) Includes an intercompany item eliminated in consolidation of $3.8 million . (c) Includes an intercompany item eliminated in consolidation of $62.9 million . 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 $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4.0 million . (c) Includes an intercompany item eliminated in consolidation of $68.2 million .
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Companys Investment In Joint Venture	September 30, 2016 December 31, 2015 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 12.7 12.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 92.7 — 82.9 Total Investment in DHLC $ 20.3 $ 113.0 $ 15.3 $ 98.2
PATH West Virginia Transmission Co, LLC [Member]
Companys Investment In Joint Venture	September 30, 2016 December 31, 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 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

Significant Accounting Matter38

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations	$ (764.2)	$ 511.8	$ 245.3	$ 1,563.4
Net Income Attributable to Noncontrolling Interests	1.6	1.3	5.3	4.1
Income (Loss) from Continuing Operations Attributable to Parent	$ (765.8)	$ 510.5	$ 240	$ 1,559.3
Weighted Average Number of Basic AEP Common Shares Outstanding	491,697,809	490,648,929	491,422,921	490,155,315
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ (1.56)	$ 1.04	$ 0.49	$ 3.18
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding	491,813,858	490,800,335	491,596,861	490,411,020
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations	$ (1.56)	$ 1.04	$ 0.49	$ 3.18
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Antidilutive Shares Outstanding			0	0
Southwestern Electric Power Co [Member]
Amounts Attributable to AEP Common Shareholders
Net Income Attributable to Noncontrolling Interests	$ 1.1	$ 1	$ 3.3	$ 3
Restricted Stock Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	100,000	200,000	200,000	200,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ 0	$ 0	$ 0	$ 0

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	$ (117.9)	$ (102.5)	$ (127.1)	$ (103.1)
Change in Fair Value Recognized in AOCI	(26.2)	(4.3)	(16)	(2.1)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	45.2	30.2	134	90.2
Purchased Electricity for Resale	774	730.8	2,134.6	2,050
Interest Expense	225.3	220.2	667.2	658.1
Reclassifications from AOCI, before Income Tax (Expense) Credit	(2.8)	(4.9)	(4.2)	(13.5)
Income Tax (Expense) Credit	534.5	(275.6)	134	(827.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(1.7)	(2)	(2.7)	(8.7)
Net Current Period Other Comprehensive Income	(27.9)	(6.3)	(18.7)	(10.8)
Pension and OPEB Adjustment Related to Mitchell Plant				5.1
Ending Balance in AOCI	(145.8)	(108.8)	(145.8)	(108.8)
Securities Available for Sale [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	8.3	8	7.1	7.7
Change in Fair Value Recognized in AOCI	0.5	(1.3)	1.7	(1)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0	0
Net Current Period Other Comprehensive Income	0.5	(1.3)	1.7	(1)
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI	8.8	6.7	8.8	6.7
Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(111.6)	(87.6)	(111.8)	(93.3)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.2	0.5	0.6	1.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.2	0.3	0.4	0.9
Net Current Period Other Comprehensive Income	0.2	0.3	0.4	0.9
Pension and OPEB Adjustment Related to Mitchell Plant				5.1
Ending Balance in AOCI	(111.4)	(87.3)	(111.4)	(87.3)
Commodity [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	1.9	(5.2)	(5.2)	1.6
Change in Fair Value Recognized in AOCI	(26.7)	(3.3)	(17.7)	(2)
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(3.6)	(5.2)	(6.5)	(15.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(2.3)	(2.2)	(4.2)	(10.3)
Net Current Period Other Comprehensive Income	(29)	(5.5)	(21.9)	(12.3)
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI	(27.1)	(10.7)	(27.1)	(10.7)
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(16.5)	(17.7)	(17.2)	(19.1)
Change in Fair Value Recognized in AOCI	0	0.3	0	0.9
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.6	(0.2)	1.7	1
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.4	(0.1)	1.1	0.7
Net Current Period Other Comprehensive Income	0.4	0.2	1.1	1.6
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI	(16.1)	(17.5)	(16.1)	(17.5)
Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	(5.4)	(19.5)	(20.7)	(36.3)
Purchased Electricity for Resale	1.8	14.3	14.2	20.4
Interest Expense	0.6	(0.2)	1.7	1
Prior Service Cost (Credit)	(4.8)	(4.8)	(14.6)	(14.6)
Actuarial (Gains)/Losses	5	5.3	15.2	16
Income Tax (Expense) Credit	(1.1)	(2.9)	(1.5)	(4.8)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0	0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	(4.8)	(4.8)	(14.6)	(14.6)
Actuarial (Gains)/Losses	5	5.3	15.2	16
Income Tax (Expense) Credit	0	0.2	0.2	0.5
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	(5.4)	(19.5)	(20.7)	(36.3)
Purchased Electricity for Resale	1.8	14.3	14.2	20.4
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	(1.3)	(3)	(2.3)	(5.6)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0	0	0	0
Purchased Electricity for Resale	0	0	0	0
Interest Expense	0.6	(0.2)	1.7	1
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0.2	(0.1)	0.6	0.3
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(3.9)	4.2	(2.8)	5
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	2.8	2.9	9.4	7.9
Purchased Electricity for Resale	69.2	80.5	240.9	258.9
Interest Expense	46.4	46.6	140.7	145.6
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.7)	(1)	(2.4)	(2.2)
Income Tax (Expense) Credit	(58.7)	(40.5)	(172.7)	(168.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.5)	(0.7)	(1.6)	(1.5)
Net Current Period Other Comprehensive Income	(0.5)	(0.7)	(1.6)	(1.5)
Ending Balance in AOCI	(4.4)	3.5	(4.4)	3.5
Appalachian Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(7.1)	0.2	(6.4)	1.1
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.5)	(0.7)	(1.6)	(2.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.3)	(0.5)	(1)	(1.4)
Net Current Period Other Comprehensive Income	(0.3)	(0.5)	(1)	(1.4)
Ending Balance in AOCI	(7.4)	(0.3)	(7.4)	(0.3)
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3.2	4	3.6	3.9
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.2)	(0.3)	(0.8)	(0.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.2)	(0.2)	(0.6)	(0.1)
Net Current Period Other Comprehensive Income	(0.2)	(0.2)	(0.6)	(0.1)
Ending Balance in AOCI	3	3.8	3	3.8
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.2)	(0.3)	(0.8)	(0.1)
Prior Service Cost (Credit)	(1.2)	(1.2)	(3.8)	(3.8)
Actuarial (Gains)/Losses	0.7	0.5	2.2	1.7
Income Tax (Expense) Credit	(0.2)	(0.3)	(0.8)	(0.7)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	(1.2)	(1.2)	(3.8)	(3.8)
Actuarial (Gains)/Losses	0.7	0.5	2.2	1.7
Income Tax (Expense) Credit	(0.2)	(0.2)	(0.6)	(0.7)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.2)	(0.3)	(0.8)	(0.1)
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0	(0.1)	(0.2)	0
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(16)	(13.8)	(16.7)	(14.3)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	3.4	0.8	13.2	2.6
Purchased Electricity for Resale	43.7	41.5	134.3	147.7
Interest Expense	26.7	23.1	76.3	68.9
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.4	1.5	1.2
Income Tax (Expense) Credit	(35.1)	(27.7)	(84.3)	(86.7)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.3	1	0.8
Net Current Period Other Comprehensive Income	0.3	0.3	1	0.8
Ending Balance in AOCI	(15.7)	(13.5)	(15.7)	(13.5)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(3.4)	0.1	(3.4)	0.1
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0	0	0	0
Net Current Period Other Comprehensive Income	0	0	0	0
Ending Balance in AOCI	(3.4)	0.1	(3.4)	0.1
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(12.6)	(13.9)	(13.3)	(14.4)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.4	1.5	1.2
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.3	1	0.8
Net Current Period Other Comprehensive Income	0.3	0.3	1	0.8
Ending Balance in AOCI	(12.3)	(13.6)	(12.3)	(13.6)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.5	0.4	1.5	1.2
Prior Service Cost (Credit)	(0.2)	(0.2)	(0.6)	(0.6)
Actuarial (Gains)/Losses	0.2	0.2	0.6	0.6
Income Tax (Expense) Credit	0.2	0.1	0.5	0.4
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	(0.2)	(0.2)	(0.6)	(0.6)
Actuarial (Gains)/Losses	0.2	0.2	0.6	0.6
Income Tax (Expense) Credit	0	0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.5	0.4	1.5	1.2
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	0.2	0.1	0.5	0.4
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI			4.3
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	1.4	2	4.8	6.4
Purchased Electricity for Resale	203.4	173.1	516.1	431.6
Interest Expense	27.2	32.6	87.7	96.3
Income Tax (Expense) Credit	(46.4)	(38.5)	(122.5)	(100.6)
Net Current Period Other Comprehensive Income			(1)	(1)
Ending Balance in AOCI	3.3		3.3
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3.5	4.9	4.3	5.6
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.5)	(1.4)	(1.6)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.2)	(0.3)	(1)	(1)
Net Current Period Other Comprehensive Income	(0.2)	(0.3)	(1)	(1)
Ending Balance in AOCI	3.3	4.6	3.3	4.6
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.3)	(0.5)	(1.4)	(1.6)
Income Tax (Expense) Credit	(0.1)	(0.2)	(0.4)	(0.6)
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI			4.2
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0.7	0.6	2.9	2.2
Purchased Electricity for Resale	130.8	103.2	315.3	253.8
Interest Expense	14.9	15	44.6	44.4
Income Tax (Expense) Credit	(32)	(27.4)	(56.6)	(51.3)
Net Current Period Other Comprehensive Income			(0.6)	(0.5)
Ending Balance in AOCI	3.6		3.6
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	3.8	4.6	4.2	5
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.3)	(0.2)	(0.9)	(0.8)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.2)	(0.1)	(0.6)	(0.5)
Net Current Period Other Comprehensive Income	(0.2)	(0.1)	(0.6)	(0.5)
Ending Balance in AOCI	3.6	4.5	3.6	4.5
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	(0.3)	(0.2)	(0.9)	(0.8)
Income Tax (Expense) Credit	(0.1)	(0.1)	(0.3)	(0.3)
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(8.9)	(6.9)	(9.4)	(7.5)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Other Revenues	0.6	0.6	1.6	1.5
Purchased Electricity for Resale	35.9	23.6	97.5	70.8
Interest Expense	32.6	29.2	92	91.4
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.5	0.3	1.2	1.3
Income Tax (Expense) Credit	(33.2)	(37.4)	(53.9)	(85.4)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.3	0.2	0.8	0.8
Net Current Period Other Comprehensive Income	0.3	0.2	0.8	0.8
Ending Balance in AOCI	(8.6)	(6.7)	(8.6)	(6.7)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(0.7)	3.1	(0.3)	3.6
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	(0.2)	(0.4)	(0.8)	(1.1)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	(0.1)	(0.2)	(0.5)	(0.7)
Net Current Period Other Comprehensive Income	(0.1)	(0.2)	(0.5)	(0.7)
Ending Balance in AOCI	(0.8)	2.9	(0.8)	2.9
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component
Beginning Balance in AOCI	(8.2)	(10)	(9.1)	(11.1)
Change in Fair Value Recognized in AOCI	0	0	0	0
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Reclassifications from AOCI, before Income Tax (Expense) Credit	0.7	0.7	2	2.4
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0.4	0.4	1.3	1.5
Net Current Period Other Comprehensive Income	0.4	0.4	1.3	1.5
Ending Balance in AOCI	(7.8)	(9.6)	(7.8)	(9.6)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.7	0.7	2	2.4
Prior Service Cost (Credit)	(0.4)	(0.5)	(1.4)	(1.4)
Actuarial (Gains)/Losses	0.2	0.1	0.6	0.3
Income Tax (Expense) Credit	0.2	0.1	0.4	0.5
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0	0	0	0
Prior Service Cost (Credit)	(0.4)	(0.5)	(1.4)	(1.4)
Actuarial (Gains)/Losses	0.2	0.1	0.6	0.3
Income Tax (Expense) Credit	(0.1)	(0.2)	(0.3)	(0.4)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Reclassifications From Accumulated Other Comprehensive Income [Abstract]
Interest Expense	0.7	0.7	2	2.4
Prior Service Cost (Credit)	0	0	0	0
Actuarial (Gains)/Losses	0	0	0	0
Income Tax (Expense) Credit	$ 0.3	$ 0.3	$ 0.7	$ 0.9

Rate Matters - Regulatory Asset

Rate Matters - Regulatory Assets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 5,182.4	$ 5,140.3
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,123	1,154.2
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	837.6	804.3
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,016.4	1,113
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	322.2	214.8
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	500.7	415.8
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	343.3	167.9
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	39.4	57.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	67.8	59.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	12.3	1.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	108.2	13.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	83.8	5.9
Amos Plant Transfer Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	2
Asset Retirement Obligation - Arkansas, Louisiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	2.5	1.7
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	12	9.7
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	12	9.7
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	7.1	4.2
Gridsmart Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	3.2	1.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1.2	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.1	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	39	22
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.6	0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.6	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1.3	1.1
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	2.2	1.1
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	9.1	0
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.2	13.1
Peak Demand Reduction/Energy Efficiency - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	12.7
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.5	0
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0.5	0
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	56.7	59.8
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	29.6	32.7
Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	27.1	27.1
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	20.8	20.9
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	9.2	9.3
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	11.6	11.6
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	161.3	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	85.9	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	75.4	0
Rockport Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	5.5	2.8
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	3.1	3.1
Storm Related Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	25.4	24.2
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	26.7	18.2
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	20.5	12.3
Stranded Costs on Retired Plant [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 3.9	$ 3.9

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)$ / MWh$ / MWDMW	Dec. 31, 2015USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 5,182.4	$ 5,140.3
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,123	1,154.2
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	837.6	804.3
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 1,016.4	$ 1,113
FERC Transmission Complaint [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.99%
Intervenor Recommended Return on Common Equity	8.32%
Indiana Amended PJM Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Percentage of Certain Transmission Expense Though the Indiana PJM Rider Approved Through 2017	43.50%
Proposed Recovery Percentage of Certain Transmission Expense through the Indiana PJM Rider from January 2017 Through June 2018	100.00%
Proposed Cap on Amounts Recovered Through the Indiana PJM Rider from January 2017 Through June 2018	$ 109
Proposed Recovery Percentage of Certain Transmission Expense Through the Indiana PJM Rider from July 2018 Until IURC Addresses in Subsequent Proceeding	100.00%
Indiana Amended PJM Settlement Agreement [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Percentage of Certain Transmission Expense Though the Indiana PJM Rider Approved Through 2017	43.50%
Proposed Recovery Percentage of Certain Transmission Expense through the Indiana PJM Rider from January 2017 Through June 2018	100.00%
Proposed Cap on Amounts Recovered Through the Indiana PJM Rider from January 2017 Through June 2018	$ 109
Proposed Recovery Percentage of Certain Transmission Expense Through the Indiana PJM Rider from July 2018 Until IURC Addresses in Subsequent Proceeding	100.00%
Kingsport 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Base Rate Increase	$ 12
Requested Return on Common Equity	10.66%
Approved Base Rate Increase	$ 8
Approved Return on Common Equity	9.85%
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.20%
Proposed Increase in PIRR Rates	$ 146
Amount of Recovery Requested for Under-Recovered Fuel Costs	$ 40
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
Energy Credit Offset Applied Against the Capacity Deferral Threshold (per MW day) | $ / MWD	147.41
Overstatement of Energy Credit Used in the Determination of the Capacity Deferral Threshold (per MW day) | $ / MWD	100
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
Annual Retail Share of Fixed Fuel Costs	$ 90
Amount of Potential Customer Credits to be Included in the PPA Rider Over the Final Four Years as Proposed in Stipulation Agreement	$ 100
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW	400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Temporary Customer-Specific Rate Impact Cap Through May 2018	5.00%
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Future Commitment To Support Development Of Large Solar Farm	$ 20
Gridsmart Investment as Proposed in Stipulation Agreement	$ 20
Significantly Excessive Earnings Test Threshold Previously Established for Ohio Power	12.00%
Significantly Excessive Earnings Test Threshold Remanded Back to the PUCO	12.00%
Intervenor Recommended Revenue Refund Related to 2014 SEET	$ 20
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return on Common Equity	10.20%
Proposed Increase in PIRR Rates	$ 146
Amount of Recovery Requested for Under-Recovered Fuel Costs	$ 40
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
Energy Credit Offset Applied Against the Capacity Deferral Threshold (per MW day) | $ / MWD	147.41
Overstatement of Energy Credit Used in the Determination of the Capacity Deferral Threshold (per MW day) | $ / MWD	100
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
Annual Retail Share of Fixed Fuel Costs	$ 90
Amount of Potential Customer Credits to be Included in the PPA Rider Over the Final Four Years as Proposed in Stipulation Agreement	$ 100
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW	400
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Temporary Customer-Specific Rate Impact Cap Through May 2018	5.00%
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Future Commitment To Support Development Of Large Solar Farm	$ 20
Gridsmart Investment as Proposed in Stipulation Agreement	$ 20
Significantly Excessive Earnings Test Threshold Previously Established for Ohio Power	12.00%
Significantly Excessive Earnings Test Threshold Remanded Back to the PUCO	12.00%
Intervenor Recommended Revenue Refund Related to 2014 SEET	$ 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
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	274
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	274
Special Rate Mechanism For Ormet [Member]
Public Utilities, General Disclosures [Line Items]
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
Percentage of Deferred Fuel Adjustment Clause Costs Attributable to Columbus Southern Power	50.00%
Percentage of Deferred Fuel Adjustment Clause Costs Attributable to Ohio Power	50.00%
Special Rate Mechanism For Ormet [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
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
Percentage of Deferred Fuel Adjustment Clause Costs Attributable to Columbus Southern Power	50.00%
Percentage of Deferred Fuel Adjustment Clause Costs Attributable to Ohio Power	50.00%
West Virginia Deferred Base Rate Increase [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Annual Delayed Customer Billing to Residential Customers	$ 25
Amount of Recovery Approved Related to Delayed Billing Including Carrying Charges	29
West Virginia Deferred Base Rate Increase [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Annual Delayed Customer Billing to Residential Customers	22
Amount of Recovery Approved Related to Delayed Billing Including Carrying Charges	27
West Virginia Expanded Net Energy Charge - 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Additional ENEC Revenues Per Settlement Agreement	38
Construction Surcharge Revenues Per Settlement Agreement	17
West Virginia Expanded Net Energy Charge - 2016 [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Additional ENEC Revenues Per Settlement Agreement	30
Construction Surcharge Revenues Per Settlement Agreement	$ 14
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
Regulatory Assets, Noncurrent	$ 239
Requested Net Increase in Deferred Capacity Costs	157
Amount of Decrease in Capacity Costs Related to Non-Deferral Portion of RSR Collections	327
Amount of Increase in Capacity Costs Related to the Correction of the Energy Credit	$ 484
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
Regulatory Assets, Noncurrent	$ 239
Requested Net Increase in Deferred Capacity Costs	157
Amount of Decrease in Capacity Costs Related to Non-Deferral Portion of RSR Collections	327
Amount of Increase in Capacity Costs Related to the Correction of the Energy Credit	$ 484

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	$ 3,651.3	$ 3,903.9
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	127.9	315.3
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	188.5	$ 751.3
Welsh Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	76
Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	$ 76
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Ownership Interest In ETT	50.00%
AEP Share Of ETT Cumulative Revenues Subject To Review	$ 545
Louisiana 2012 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share Of Turk Plant	29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement	$ 2
Base Rate Increase per Settlement Agreement	85
Fuel Rate Decrease per 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 Turk Plant	29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement	$ 2
Base Rate Increase per Settlement Agreement	85
Fuel Rate Decrease per 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 Base Rate Case - 2015 [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 Fuel Adjustment Clause	$ 4
Requested Return on Common Equity	10.50%
Future Incremental Purchased Capacity And Energy Costs Related To Environmental Projects	$ 35
Interim Annual Base Rate Increase	$ 75
Administrative Law Judge Recommended Return on Common Equity	9.25%
Administrative Law Judge Recommended Environmental Compliance Plan Cost Cap	$ 210
Administrative Law Judge Recommended Increase in Depreciation Expense	14
Administrative Law Judge Recommended Annual Increase in Revenues	47
Commission Staff Recommended Annual Increase in Revenues	32
Oklahoma Base Rate Case - 2015 [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 Fuel Adjustment Clause	$ 4
Requested Return on Common Equity	10.50%
Future Incremental Purchased Capacity And Energy Costs Related To Environmental Projects	$ 35
Interim Annual Base Rate Increase	$ 75
Administrative Law Judge Recommended Return on Common Equity	9.25%
Administrative Law Judge Recommended Environmental Compliance Plan Cost Cap	$ 210
Administrative Law Judge Recommended Increase in Depreciation Expense	14
Administrative Law Judge Recommended Annual Increase in Revenues	47
Commission Staff Recommended Annual Increase in Revenues	32
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	87
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	87
SPP Open Access Transmission Tariff Upgrade Costs [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact	7
SPP Open Access Transmission Tariff Upgrade Costs [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact	3
SPP Open Access Transmission Tariff Upgrade Costs [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact	4
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
TCC Distribution Cost Recovery Factor [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Approved in Settlement Agreement	45
TNC Distribution Cost Recovery Factor [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Approved in Settlement Agreement	11
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	850
Construction Work in Progress	395
Remaining Contractual Construction Obligations	14
Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	69
Amount of Additional Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	10
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	79
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	850
Construction Work in Progress	395
Remaining Contractual Construction Obligations	14
Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	69
Amount of Additional Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	10
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs	79
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	632
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	632
Minimum [Member] | Oklahoma Base Rate Case - 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider	$ 10
Intervenor Recommended Return on Common Equity	8.75%
Intervenor Recommended Increase to Depreciation Expense	$ 23
Minimum [Member] | Oklahoma Base Rate Case - 2015 [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	8.75%
Intervenor Recommended Increase to Depreciation Expense	$ 23
Maximum [Member] | Oklahoma Base Rate Case - 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Increase to Annual Revenue and/or Rider	$ 31
Intervenor Recommended Return on Common Equity	9.30%
Intervenor Recommended Increase to Depreciation Expense	$ 46
Maximum [Member] | Oklahoma Base Rate Case - 2015 [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	9.30%
Intervenor Recommended Increase to Depreciation Expense	$ 46
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	43
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	43
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	180
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress	180
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	219
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [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
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Completed Project Capital Costs	370
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]
Completed Project Capital Costs	$ 370

Commitments, Guarantees and C43

Commitments, Guarantees and Contingencies (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	$ 147.2
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	291.4
Bilateral Letters of Credit	294.7
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	3,500
Letters of Credit Limit	1,200
Uncommitted Facility	300
Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	36.8
Boat and Barge Leases [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantee Liability related to AEPRO Boat and Barge Leases	14
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Current Liabilities	3
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Noncurrent Liabilities	11
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases	87
Appalachian Power Co [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	104.4
Bilateral Letters of Credit	105.6
Appalachian Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	5.5
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] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.4
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations for Remaining Railcars	$ 9
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee	$ 9
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	4.2
Ohio Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	5.8
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3
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	68
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent	15
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	53
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3.5
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Future Minimum Lease Obligations for Remaining Railcars	$ 11
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee	$ 10
Superfund and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	8
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	8
June 2017 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	1,750
June 2021 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	3,000
July 2018 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	1,750
June 2018 [Member] | Letters of Credit [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	$ 500

Dispositions, Assets and Liab44

Dispositions, Assets and Liabilities Held for Sale and Impairments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	$ 0	$ 7.8	$ (2.5)	$ 18.2
Total Assets Classified as Held for Sale on the Balance Sheets	1,915.3		1,915.3
Total Liabilities Classified as Held for Sale on the Balance Sheets	231		231
Asset Impairments and Other Related Charges	2,264.9	0	2,264.9	0
Indiana Michigan Power Co [Member]
Asset Impairments and Other Related Charges	10.5	0	10.5	0
Corporate and Other [Member]
Other Revenues		129.1		372.2
Other Operation Expense		96.7		273.1
Maintenance Expense		4.2		19.9
Depreciation and Amortization Expense		8.8		26.9
Taxes Other Than Income Taxes		2.7		9.9
Total Expense		112.4		329.8
Other Expense		(5.4)		(14.5)
Pretax Income of Discontinued Operations		11.3		27.9
Income Tax Expense		3.6		9.7
Equity Earnings of Unconsolidated Subsidiaries		0.1		0
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income		7.8		18.2
Vertically Integrated Utilities [Member]
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	0	0	0	0
Total Assets Classified as Held for Sale on the Balance Sheets	0		0
Total Liabilities Classified as Held for Sale on the Balance Sheets	0		0
Generation And Marketing [Member]
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income	0	0	0	0
Fuel	139.7		139.7
Materials and Supplies	48.7		48.7
Property, Plant and Equipment - Net	1,726.5		1,726.5
Other Class of Assets That Are Not Major	0.4		0.4
Total Assets Classified as Held for Sale on the Balance Sheets	1,915.3		1,915.3
Long-term Debt	134.8		134.8
Waterford Plant Upgrade Liability	53.1		53.1
Asset Retirement Obligations	36.3		36.3
Other Classes of Liabilities That Are Not Major	6.8		6.8
Total Liabilities Classified as Held for Sale on the Balance Sheets	231		231
Discontinued Operations and Disposal Groups (Textuals)
Cash Proceeds from Sale of Disposition Plants, Net			2,200
Pretax Income (Loss) of Disposal Group	116	$ 118	312	404
Generation And Marketing [Member] | I&M Price River Coal Reserves [Member]
Public Utilities, Property, Plant and Equipment, Net	11		11
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member]
Public Utilities, Property, Plant and Equipment, Net	2,139.4		2,139.4
Fair Value of Generating Unit	0		0
Asset Impairments and Other Related Charges			2,139.4
Generation And Marketing [Member] | Trent and Desert Sky Wind Farms [Member]
Public Utilities, Property, Plant and Equipment, Net	118.7		118.7
Fair Value of Generating Unit	46		46
Asset Impairments and Other Related Charges			72.7
Generation And Marketing [Member] | Coal Reserves [Member]
Public Utilities, Property, Plant and Equipment, Net	56.6		56.6
Fair Value of Generating Unit	3.8		3.8
Asset Impairments and Other Related Charges			52.8
Generation And Marketing [Member] | Total Impaired Assets [Member]
Public Utilities, Property, Plant and Equipment, Net	2,314.7		2,314.7
Fair Value of Generating Unit	$ 49.8		49.8
Asset Impairments and Other Related Charges			2,264.9
Tanners Creek Plant Units 1 Through 4 [Member] | Vertically Integrated Utilities [Member]
Discontinued Operations and Disposal Groups (Textuals)
Payment On Sale Of Property Plant And Equipment			$ 92
Muskingum River Plant [Member] | Generation And Marketing [Member]
Discontinued Operations and Disposal Groups (Textuals)
Payment On Sale Of Property Plant And Equipment				48
Gain on Sale of Muskingum River Plant				$ 32

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 21.4	$ 23.4	$ 64.3	$ 70.1
Interest Cost	52.9	51.3	158.7	153.9
Expected Return on Plan Assets	(70.1)	(68.6)	(210.2)	(206)
Amortization of Prior Service Cost (Credit)	0.6	0.5	1.7	1.7
Amortization of Net Actuarial Loss	21	26.7	62.9	80.3
Net Periodic Benefit Cost (Credit)	25.8	33.3	77.4	100
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.1	2.1	6.1	6.5
Interest Cost	6.8	6.7	20.4	20.1
Expected Return on Plan Assets	(8.8)	(8.7)	(26.5)	(26.2)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2.6	3.5	8	10.4
Net Periodic Benefit Cost (Credit)	2.7	3.6	8.1	10.9
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3.1	3.3	9.2	9.7
Interest Cost	6.3	6.1	19	18.3
Expected Return on Plan Assets	(8.4)	(8.1)	(25.2)	(24.3)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2.5	3.1	7.4	9.4
Net Periodic Benefit Cost (Credit)	3.5	4.4	10.5	13.2
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.6	1.6	4.9	5
Interest Cost	5.1	5.1	15.4	15.2
Expected Return on Plan Assets	(6.9)	(6.8)	(20.8)	(20.6)
Amortization of Prior Service Cost (Credit)	0	0	0.1	0.1
Amortization of Net Actuarial Loss	2.1	2.6	6.1	7.9
Net Periodic Benefit Cost (Credit)	1.9	2.5	5.7	7.6
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1.5	1.6	4.6	4.8
Interest Cost	2.8	2.7	8.4	8.2
Expected Return on Plan Assets	(3.9)	(3.8)	(11.6)	(11.4)
Amortization of Prior Service Cost (Credit)	0.1	0.1	0.2	0.2
Amortization of Net Actuarial Loss	1.1	1.5	3.3	4.3
Net Periodic Benefit Cost (Credit)	1.6	2.1	4.9	6.1
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2	2.2	6.1	6.3
Interest Cost	3.1	2.9	9.3	8.8
Expected Return on Plan Assets	(4)	(4)	(12.3)	(12)
Amortization of Prior Service Cost (Credit)	0	0	0.2	0.2
Amortization of Net Actuarial Loss	1.2	1.5	3.6	4.5
Net Periodic Benefit Cost (Credit)	2.3	2.6	6.9	7.8
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	2.6	3.1	7.7	9.2
Interest Cost	15.3	14.2	45.7	42.6
Expected Return on Plan Assets	(26.8)	(27.7)	(80.3)	(83.3)
Amortization of Prior Service Cost (Credit)	(17.3)	(17.3)	(51.8)	(51.8)
Amortization of Net Actuarial Loss	7.8	4.7	23.5	14.1
Net Periodic Benefit Cost (Credit)	(18.4)	(23)	(55.2)	(69.2)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.3	0.7	0.9
Interest Cost	2.7	2.5	8.1	7.7
Expected Return on Plan Assets	(4.3)	(4.5)	(13)	(13.6)
Amortization of Prior Service Cost (Credit)	(2.5)	(2.5)	(7.5)	(7.5)
Amortization of Net Actuarial Loss	1.4	0.9	4.1	2.7
Net Periodic Benefit Cost (Credit)	(2.5)	(3.3)	(7.6)	(9.8)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.4	0.4	1.1	1.2
Interest Cost	1.7	1.6	5.2	4.8
Expected Return on Plan Assets	(3.2)	(3.3)	(9.6)	(9.9)
Amortization of Prior Service Cost (Credit)	(2.4)	(2.4)	(7.1)	(7.1)
Amortization of Net Actuarial Loss	0.9	0.5	2.8	1.5
Net Periodic Benefit Cost (Credit)	(2.6)	(3.2)	(7.6)	(9.5)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.6	0.6
Interest Cost	1.8	1.6	5.3	4.8
Expected Return on Plan Assets	(3.3)	(3.4)	(9.7)	(10.1)
Amortization of Prior Service Cost (Credit)	(1.7)	(1.8)	(5.2)	(5.2)
Amortization of Net Actuarial Loss	0.9	0.6	2.8	1.6
Net Periodic Benefit Cost (Credit)	(2.1)	(2.8)	(6.2)	(8.3)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.5	0.5
Interest Cost	0.8	0.8	2.4	2.3
Expected Return on Plan Assets	(1.5)	(1.5)	(4.5)	(4.7)
Amortization of Prior Service Cost (Credit)	(1.1)	(1.1)	(3.2)	(3.2)
Amortization of Net Actuarial Loss	0.4	0.2	1.3	0.7
Net Periodic Benefit Cost (Credit)	(1.2)	(1.4)	(3.5)	(4.4)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	0.2	0.2	0.6	0.6
Interest Cost	0.9	0.8	2.7	2.5
Expected Return on Plan Assets	(1.7)	(1.7)	(5)	(5.2)
Amortization of Prior Service Cost (Credit)	(1.3)	(1.3)	(3.9)	(3.8)
Amortization of Net Actuarial Loss	0.5	0.3	1.5	0.8
Net Periodic Benefit Cost (Credit)	$ (1.4)	$ (1.7)	$ (4.1)	$ (5.1)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Reportable Segment Information
Revenues		$ 4,652.2	$ 4,431.4	$ 12,590	$ 12,838.5
Income (Loss) from Continuing Operations		(764.2)	511.8	245.3	1,563.4
Income (Loss) from Discontinued Operations, Net of Tax		0	7.8	(2.5)	18.2
Net Income (Loss)		(764.2)	519.6	242.8	1,581.6
Balance Sheet Information
Total Property, Plant and Equipment		60,599.8		60,599.8		$ 65,481.4
Accumulated Depreciation and Amortization		16,337.6		16,337.6		19,348.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		44,262.2		44,262.2		46,133.2
Assets Held for Sale		1,915.3		1,915.3
Total Assets		61,442		61,442		61,683.1
Long-term Debt Due Within One Year		2,384.8		2,384.8		1,831.8
Long-term Debt - Affiliated		0		0		0
Long-term Debt		17,319.9		17,319.9		17,740.9
Total Long-term Debt Outstanding		19,704.7		19,704.7		19,572.7
Liabilities Held for Sale		231		231
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		2,538.3	2,435.8	6,864.6	7,081.8
Revenues		2,556.3	2,471.5	6,927.8	7,159.1
Income (Loss) from Continuing Operations		343.4	274.5	832.6	782.7
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		343.4	274.5	832.6	782.7
Balance Sheet Information
Total Property, Plant and Equipment		41,015.6		41,015.6		40,130.3
Accumulated Depreciation and Amortization		12,549.8		12,549.8		12,335
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		28,465.8		28,465.8		27,795.3
Assets Held for Sale		0		0
Total Assets		36,924.3		36,924.3		35,792.3
Long-term Debt Due Within One Year		1,611		1,611		935.4
Long-term Debt - Affiliated		20		20		20
Long-term Debt		10,067.3		10,067.3		9,833
Total Long-term Debt Outstanding		11,698.3		11,698.3		10,788.4
Liabilities Held for Sale		0		0
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		1,245.4	1,163.6	3,398.9	3,377.9
Revenues		1,275.6	1,188.6	3,468.5	3,519.4
Income (Loss) from Continuing Operations		155.5	113	388.1	287.8
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		155.5	113	388.1	287.8
Balance Sheet Information
Total Property, Plant and Equipment		14,438.4		14,438.4		13,840.5
Accumulated Depreciation and Amortization		3,647.4		3,647.4		3,529.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		10,791		10,791		10,311.3
Assets Held for Sale		0		0
Total Assets		14,155.7		14,155.7		14,640.2
Long-term Debt Due Within One Year		268.3		268.3		824.7
Long-term Debt - Affiliated		0		0		0
Long-term Debt		4,745.3		4,745.3		4,776.8
Total Long-term Debt Outstanding		5,013.6		5,013.6		5,601.5
Liabilities Held for Sale		0		0
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales Revenue, Net		39.5	26.9	110.1	74.1
Revenues		132.4	87.5	382.7	244.9
Income (Loss) from Continuing Operations		69.5	45.9	209.5	147.7
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		69.5	45.9	209.5	147.7
Balance Sheet Information
Total Property, Plant and Equipment		4,896.4		4,896.4		3,977.6
Accumulated Depreciation and Amortization		88.2		88.2		52.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,808.2		4,808.2		3,925.3
Assets Held for Sale		0		0
Total Assets		5,780.5		5,780.5		5,012.1
Long-term Debt Due Within One Year		0		0		0
Long-term Debt - Affiliated		0		0		0
Long-term Debt		1,660.4		1,660.4		1,648.4
Total Long-term Debt Outstanding		1,660.4		1,660.4		1,648.4
Liabilities Held for Sale		0		0
Generation And Marketing [Member]
Reportable Segment Information
Sales Revenue, Net		823.3	801.8	2,192.5	2,288.6
Revenues		859.4	836	2,291.2	2,806.7
Income (Loss) from Continuing Operations		(1,369.2)	91.6	(1,248.8)	360.3
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		(1,369.2)	91.6	(1,248.8)	360.3
Balance Sheet Information
Total Property, Plant and Equipment		234.3		234.3		7,461.3
Accumulated Depreciation and Amortization		44.2		44.2		3,367
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		190.1		190.1		4,094.3
Assets Held for Sale		1,915.3		1,915.3
Total Assets		3,176.6		3,176.6		5,414.5
Long-term Debt Due Within One Year		505.2		505.2		71.6
Long-term Debt - Affiliated		32.2		32.2		32.2
Long-term Debt		0		0		639.5
Total Long-term Debt Outstanding		537.4		537.4		743.3
Liabilities Held for Sale		231		231
All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[1]	5.7	3.3	23.9	16.1
Revenues	[1]	24.8	23.8	79.1	73.9
Income (Loss) from Continuing Operations	[1]	36.6	(13.2)	63.9	(15.1)
Income (Loss) from Discontinued Operations, Net of Tax	[1]	0	7.8	(2.5)	18.2
Net Income (Loss)	[1]	36.6	(5.4)	61.4	3.1
Balance Sheet Information
Total Property, Plant and Equipment	[1]	368.6		368.6		350.9
Accumulated Depreciation and Amortization	[1]	192.1		192.1		176.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	176.5		176.5		174
Assets Held for Sale		0		0
Total Assets	[1]	21,772.4		21,772.4		21,907.4
Long-term Debt Due Within One Year	[1]	0.3		0.3		0.1
Long-term Debt - Affiliated	[1]	0		0		0
Long-term Debt	[1]	846.9		846.9		843.2
Total Long-term Debt Outstanding	[1]	847.2		847.2		843.3
Liabilities Held for Sale		0		0
Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		(196.3)	(176)	(559.3)	(965.5)
Segment Reconciling Items [Member] | Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		18	35.7	63.2	77.3
Segment Reconciling Items [Member] | Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		30.2	25	69.6	141.5
Segment Reconciling Items [Member] | AEP Transmission Holdco [Member]
Reportable Segment Information
Sales Revenue, Net		92.9	60.6	272.6	170.8
Segment Reconciling Items [Member] | Generation And Marketing [Member]
Reportable Segment Information
Sales Revenue, Net		36.1	34.2	98.7	518.1
Segment Reconciling Items [Member] | All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[1]	19.1	20.5	55.2	57.8
Consolidation, Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net		0	0	0	0
Revenues		(196.3)	(176)	(559.3)	(965.5)
Income (Loss) from Continuing Operations		0	0	0	0
Income (Loss) from Discontinued Operations, Net of Tax		0	0	0	0
Net Income (Loss)		0	$ 0	0	$ 0
Balance Sheet Information
Total Property, Plant and Equipment	[2]	(353.5)		(353.5)		(279.2)
Accumulated Depreciation and Amortization	[2]	(184.1)		(184.1)		(112.2)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[2]	(169.4)		(169.4)		(167)
Assets Held for Sale		0		0
Total Assets	[2],[3]	(20,367.5)		(20,367.5)		(21,083.4)
Long-term Debt Due Within One Year		0		0		0
Long-term Debt - Affiliated		(52.2)		(52.2)		(52.2)
Long-term Debt		0		0		0
Total Long-term Debt Outstanding		(52.2)		(52.2)		$ (52.2)
Liabilities Held for Sale		$ 0		$ 0
[1]	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.
[2]	Includes eliminations due to an intercompany capital lease.
[3]	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2016USD ($)MWhMMBTUTgal		Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)MWhMMBTUTgal		Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)MWhMMBTUTgal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 7.1			$ 7.1			$ 5.8
Cash Collateral Paid Netted Against Risk Management Liabilities		36			36			44.4
Fair Value of Derivative Instruments
Current Risk Management Assets		110.8			110.8			134.4
Long-term Risk Management Assets		311.7			311.7			321.8
Total Assets		422.5			422.5			456.2
Current Risk Management Liabilities		79.3			79.3			87.1
Long-term Risk Management Liabilities		240			240			179.1
Total Liabilities		319.3			319.3			266.2
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		18.5		$ (20)	62.3		$ 100
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		(1.1)		3.7	3		6.8
Gain (Loss) on Fair Value Portion of Long Term Debt		1.1		(3.7)	(3)		(6.8)
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		23.9			23.9			17.5
Amount of Collateral Attributable to Other Contracts	[1]	292.4			292.4			297.8
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		285.8			285.8			300.1
Amount of Cash Collateral Posted		10.6			10.6			0.8
Additional Settlement Liability if Cross Default Provision is Triggered		253.8			$ 253.8			240.6
Derivatives and Hedging (Textuals) [Abstract]
Maximum Term for Exposure to Variability of Future Cash Flows					135 months
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.1			$ 0.1			0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.1			0.1			3.1
Fair Value of Derivative Instruments
Current Risk Management Assets		3.2			3.2			14.7
Long-term Risk Management Assets		0.2			0.2			0.1
Current Risk Management Liabilities		10.7			10.7			4.8
Long-term Risk Management Liabilities		0.3			0.3			0.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		23.8		5.4	35.6		37
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		4.4			4.4			4.9
Amount of Collateral Attributable to Other Contracts		0			0			0.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		1.3			1.3			3.7
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		1.3			1.3			3.7
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.3			0.3			0.6
Fair Value of Derivative Instruments
Current Risk Management Assets		5.2			5.2			10.6
Long-term Risk Management Assets		0.2			0.2			0
Current Risk Management Liabilities		1.3			1.3			6.3
Long-term Risk Management Liabilities		0.2			0.2			1.6
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		8.4		0.8	23.7		10.7
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		2.7			2.7			3.3
Amount of Collateral Attributable to Other Contracts		0			0			0.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0.8			0.8			2.5
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0.8			0.8			2.5
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0.5
Fair Value of Derivative Instruments
Long-term Risk Management Assets		0			0			19.2
Current Risk Management Liabilities		5.6			5.6			3.6
Long-term Risk Management Liabilities		103.5			103.5			0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(95.5)		(23.4)	(131.6)		(26.5)
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0.3
Fair Value of Derivative Instruments
Current Risk Management Assets		1.1			1.1			0.6
Current Risk Management Liabilities		0			0			0.2
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.8		(0.9)	3.3		5.2
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		3.9			3.9			0
Amount of Collateral Attributable to Other Contracts		3.2			3.2			3.2
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		0			0			0.3
Fair Value of Derivative Instruments
Current Risk Management Assets		1.4			1.4			0.8
Current Risk Management Liabilities		0			0			3.1
Long-term Risk Management Liabilities		0			0			2.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.3		1.1	19.7		12.6
Collateral Triggering Events [Abstract]
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		4.7			4.7			0
Amount of Collateral Attributable to Other Contracts		0.1			0.1			0.1
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[2]	415.6	[3]		415.6	[3]		438.5	[4]
Total Liabilities	[2]	270.3	[3]		270.3	[3]		236.6	[4]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	3.4			3.4			15.7
Total Liabilities	[2],[5]	11			11			4.9
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	5.4			5.4			12.3
Total Liabilities	[2],[5]	1.5			1.5			7.9
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0			0			19.2
Total Liabilities	[2],[5]	109.1			109.1			3.6
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	1.1			1.1			0.6
Total Liabilities	[2],[5]	0			0			0.2
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	1.4			1.4			0.8
Total Liabilities	[2],[5]	0			0			5.2
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[6]	6.5			6.5			17.6
Hedging Liabilities	[6]	48.4			48.4			26.1
AOCI Gain (Loss) Net of Tax		(27.1)			(27.1)			(5.2)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0.9			(0.4)
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50			50			50
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	267			267			368.8
Long-term Risk Management Assets	[7]	364.2			364.2			364.8
Total Assets	[7]	631.2			631.2			733.6
Current Risk Management Liabilities	[7]	241.5			241.5			347
Long-term Risk Management Liabilities	[7]	273.3			273.3			223.3
Total Liabilities	[7]	514.8			514.8			570.3
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	116.4			116.4			163.3
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	11			11			25.9
Long-term Risk Management Assets	[8]	1			1			0.3
Total Assets	[8]	12			12			26.2
Current Risk Management Liabilities	[8]	18.5			18.5			18.1
Long-term Risk Management Liabilities	[8]	1.1			1.1			0.3
Total Liabilities	[8]	19.6			19.6			18.4
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(7.6)			(7.6)			7.8
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	10.8			10.8			22.8
Long-term Risk Management Assets	[8]	0.6			0.6			0.6
Total Assets	[8]	11.4			11.4			23.4
Current Risk Management Liabilities	[8]	7.2			7.2			17
Long-term Risk Management Liabilities	[8]	0.6			0.6			2.6
Total Liabilities	[8]	7.8			7.8			19.6
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	3.6			3.6			3.8
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.1			0.1			0
Long-term Risk Management Assets	[8]	0			0			19.2
Total Assets	[8]	0.1			0.1			19.2
Current Risk Management Liabilities	[8]	5.7			5.7			4.1
Long-term Risk Management Liabilities	[8]	103.5			103.5			0
Total Liabilities	[8]	109.2			109.2			4.1
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(109.1)			(109.1)			15.1
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	1.2			1.2			0.6
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	1.2			1.2			0.6
Current Risk Management Liabilities	[8]	0.1			0.1			0.5
Long-term Risk Management Liabilities	[8]	0			0			0
Total Liabilities	[8]	0.1			0.1			0.5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	1.1			1.1			0.1
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	1.5			1.5			0.8
Long-term Risk Management Assets	[8]	0			0			0
Total Assets	[8]	1.5			1.5			0.8
Current Risk Management Liabilities	[8]	0.1			0.1			3.4
Long-term Risk Management Liabilities	[8]	0			0			2.1
Total Liabilities	[8]	0.1			0.1			5.5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	1.4			1.4			(4.7)
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	8			8			8.2
Long-term Risk Management Assets	[7]	5.4			5.4			11.7
Total Assets	[7]	13.4			13.4			19.9
Current Risk Management Liabilities	[7]	6.6			6.6			9.1
Long-term Risk Management Liabilities	[7]	48.7			48.7			19.3
Total Liabilities	[7]	55.3			55.3			28.4
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(41.9)			(41.9)			(8.5)
Interest Rate and Foreign Currency [Member]
Commodity:
Derivative, Notional Amount		505.2			505.2			560.3
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[6]	0			0			0
Hedging Liabilities	[6]	0.2			0.2			0.4
AOCI Gain (Loss) Net of Tax		(16.1)			(16.1)			(17.2)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1.2)			(1.5)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		3			3			3.6
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0.7			0.7
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(12.3)			(12.3)			(13.3)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1.3)			(1.3)
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		3.3			3.3			4.3
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1.1			1.2
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		3.6			3.6			4.2
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			0
Impact of Cash Flow Hedges on the Condensed Balance Sheet
AOCI Gain (Loss) Net of Tax		(7.8)			(7.8)			(9.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1.5)			(1.7)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0.3			0.3			0.1
Long-term Risk Management Assets	[7]	0			0			0
Total Assets	[7]	0.3			0.3			0.1
Current Risk Management Liabilities	[7]	0.2			0.2			0.3
Long-term Risk Management Liabilities	[7]	0.3			0.3			3.2
Total Liabilities	[7]	0.5			0.5			3.5
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(0.2)			(0.2)			(3.4)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		275.3			275.3			377.1
Long-term Risk Management Assets		369.6			369.6			376.5
Total Assets		644.9			644.9			753.6
Current Risk Management Liabilities		248.3			248.3			356.4
Long-term Risk Management Liabilities		322.3			322.3			245.8
Total Liabilities		570.6			570.6			602.2
Total MTM Derivative Contract Net Assets (Liabilities)		74.3			74.3			151.4
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(164.5)			(164.5)			(242.7)
Long-term Risk Management Assets	[9]	(57.9)			(57.9)			(54.7)
Total Assets	[9]	(222.4)			(222.4)			(297.4)
Current Risk Management Liabilities	[9]	(169)			(169)			(269.3)
Long-term Risk Management Liabilities	[9]	(82.3)			(82.3)			(66.7)
Total Liabilities	[9]	(251.3)			(251.3)			(336)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	28.9			28.9			38.6
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(7.8)			(7.8)			(10.3)
Long-term Risk Management Assets	[10]	(0.8)			(0.8)			(0.2)
Total Assets	[10]	(8.6)			(8.6)			(10.5)
Current Risk Management Liabilities	[10]	(7.8)			(7.8)			(13.3)
Long-term Risk Management Liabilities	[10]	(0.8)			(0.8)			(0.2)
Total Liabilities	[10]	(8.6)			(8.6)			(13.5)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			3
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]	(5.6)			(5.6)			(10.5)
Long-term Risk Management Assets	[10]	(0.4)			(0.4)			(0.6)
Total Assets	[10]	(6)			(6)			(11.1)
Current Risk Management Liabilities	[10]	(5.9)			(5.9)			(10.7)
Long-term Risk Management Liabilities	[10]	(0.4)			(0.4)			(1)
Total Liabilities	[10]	(6.3)			(6.3)			(11.7)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.3			0.3			0.6
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	(0.1)			(0.1)			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	(0.1)			(0.1)			0
Current Risk Management Liabilities	[10]	(0.1)			(0.1)			(0.5)
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	(0.1)			(0.1)			(0.5)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0.5
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]	(0.1)			(0.1)			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	(0.1)			(0.1)			0
Current Risk Management Liabilities	[10]	(0.1)			(0.1)			(0.3)
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	(0.1)			(0.1)			(0.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0.3
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]	(0.1)			(0.1)			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	(0.1)			(0.1)			0
Current Risk Management Liabilities	[10]	(0.1)			(0.1)			(0.3)
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	(0.1)			(0.1)			(0.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0.3
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	110.8			110.8			134.4
Long-term Risk Management Assets	[11]	311.7			311.7			321.8
Total Assets	[11]	422.5			422.5			456.2
Current Risk Management Liabilities	[11]	79.3			79.3			87.1
Long-term Risk Management Liabilities	[11]	240			240			179.1
Total Liabilities	[11]	319.3			319.3			266.2
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	103.2			103.2			190
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]	3.2			3.2			15.6
Long-term Risk Management Assets	[12]	0.2			0.2			0.1
Total Assets	[12]	3.4			3.4			15.7
Current Risk Management Liabilities	[12]	10.7			10.7			4.8
Long-term Risk Management Liabilities	[12]	0.3			0.3			0.1
Total Liabilities	[12]	11			11			4.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(7.6)			(7.6)			10.8
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]	5.2			5.2			12.3
Long-term Risk Management Assets	[12]	0.2			0.2			0
Total Assets	[12]	5.4			5.4			12.3
Current Risk Management Liabilities	[12]	1.3			1.3			6.3
Long-term Risk Management Liabilities	[12]	0.2			0.2			1.6
Total Liabilities	[12]	1.5			1.5			7.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	3.9			3.9			4.4
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	0			0			0
Long-term Risk Management Assets	[12]	0			0			19.2
Total Assets	[12]	0			0			19.2
Current Risk Management Liabilities	[12]	5.6			5.6			3.6
Long-term Risk Management Liabilities	[12]	103.5			103.5			0
Total Liabilities	[12]	109.1			109.1			3.6
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(109.1)			(109.1)			15.6
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]	1.1			1.1			0.6
Long-term Risk Management Assets	[12]	0			0			0
Total Assets	[12]	1.1			1.1			0.6
Current Risk Management Liabilities	[12]	0			0			0.2
Long-term Risk Management Liabilities	[12]	0			0			0
Total Liabilities	[12]	0			0			0.2
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	1.1			1.1			0.4
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]	1.4			1.4			0.8
Long-term Risk Management Assets	[12]	0			0			0
Total Assets	[12]	1.4			1.4			0.8
Current Risk Management Liabilities	[12]	0			0			3.1
Long-term Risk Management Liabilities	[12]	0			0			2.1
Total Liabilities	[12]	0			0			5.2
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	$ 1.4			$ 1.4			$ (4.4)
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		398.7			398.7			317.8
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		66.4			66.4			40.9
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		22.4			22.4			22.8
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		11.3			11.3			13.3
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		18.3			18.3			11.3
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		21.8			21.8			14
Coal [Member]
Commodity:
Derivative, Mass Notional Amount | T		2.1			2.1			4.4
Coal [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0.7			0.7			1.6
Coal [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		1.4			1.4			2.8
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		37.3			37.3			38.2
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0.3
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0.2
Natural Gas [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0.2
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0.2
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		6.9			6.9			7.4
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.3			1.3			1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.6			0.6			0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1.5			1.5			1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.8			0.8			0.8
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		0.9			0.9			0.9
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 82.2			$ 82.2			$ 113.5
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		0.1			0.1			2.4
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		0.1			0.1			1.6
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			$ 0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		2.4			3.1		6.7
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		0.1		(0.9)	0.1		(0.9)
Transmission and Distribution Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Transmission and Distribution Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Transmission and Distribution Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Transmission and Distribution Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Transmission and Distribution Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		9.2		1	50.1		59.9
Generation and Marketing Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1		(0.4)	(0.8)		0.8
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1.2		0.4	3.7		3.6
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.1		(0.9)	0.1		(0.9)
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	0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		0	(0.1)		0
Sales to AEP Affiliates [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0	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				1.2	2.1		1.5
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				3.3	5.8		4.3
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		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		0
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts				0	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		1.5		1.6	4.9		5.3
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.8		0.8	2.7		1.6
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.1		0	0.2		0.3
Purchased Electricity for Resale [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.4)		(0.7)	(1.3)		(2.3)
Other Operation Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)	(0.1)		(0.3)
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)	(0.1)		(0.2)
Other Operation Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.1)	(0.3)		(0.4)
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)	(0.1)		(0.3)
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)	(0.2)		(0.4)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.4)		(0.8)	(1.6)		(2.2)
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.2)	(0.3)		(0.5)
Maintenance Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		(0.1)	(0.1)		(0.2)
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.1)	(0.3)		(0.4)
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		(0.1)		(0.1)	(0.2)		(0.2)
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.1)	(0.2)		(0.3)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(22.5)		0.1	(51)		0.2
Regulatory Assets [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	5.2		0.9	(7.2)		2.1
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]	1.6		(1)	3		(1.2)
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]	(95.4)		0	(115.9)		0
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]	0.1		(0.2)	0.4		0.6
Regulatory Assets [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	2.8		0.2	5.5		(1.2)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	28.6		(20.3)	58		33.3
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]	16.9		3.2	39.2		31.8
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]	5.5		(1.7)	11.2		4.1
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]	0		(22.3)	(15.2)		(24.8)
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]	0.8		(0.5)	3.2		5.1
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]	$ 3.7		$ 1.1	$ 14.7		$ 14.5
[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 September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts.
[4]	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.
[5]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[6]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
[7]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[8]	Derivative instruments within this category 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 include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[10]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[11]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[12]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[13]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 19,704.7		$ 19,704.7		$ 19,572.7
Long Term Debt, Fair Value						21,201.3
Other Temporary Investments
Cost		265.7		265.7		375.8
Gross Unrealized Gains		13.5		13.5		11.7
Gross Unrealized Losses		0		0		(0.7)
Fair Value		279.2		279.2		386.8
Debt and Equity Securities Within Other Temporary Investments
Proceeds from Investment Sales		0	$ 0	0	$ 0
Purchases of Investments		0.6	9.5	1.6	10.3
Gross Realized Gains on Investment Sales		0	0	0	0
Gross Realized Losses on Investment Sales		0	0	0	0
Nuclear Trust Fund Investments
Fair Value		2,230.8		2,230.8		2,106.4
Gross Unrealized Gains		694.4		694.4		611.8
Other-Than-Temporary Impairments		(81.4)		(81.4)		(83.3)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		650	921.5	2,427	1,437.3
Purchases of Investments		656.5	938.4	2,452.9	1,479.1
Gross Realized Gains on Investment Sales		13.9	15	41.9	33.8
Gross Realized Losses on Investment Sales		6.5	13.1	22.2	22.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,230.8		2,230.8		2,106.4
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		913		913		771
Adjusted Cost of Domestic Equity Securities		588		588		555
Includes Debt Included In Liabilities Held For Sale [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding	[1],[2]	19,839.5		19,839.5
Long Term Debt, Fair Value		22,840.4		22,840.4
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		4,033.1		4,033.1		3,930.7
Long Term Debt, Fair Value		4,941.8		4,941.8		4,416.7
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,407.4		2,407.4		2,000
Long Term Debt, Fair Value		2,717.8		2,717.8		2,193.6
Nuclear Trust Fund Investments
Fair Value		2,230.8		2,230.8		2,106.4
Gross Unrealized Gains		694.4		694.4		611.8
Other-Than-Temporary Impairments		(81.4)		(81.4)		(83.3)
Securities Activity Within Decommissioning and SNF Trusts
Proceeds from Investment Sales		650	921.5	2,427	1,437.3
Purchases of Investments		656.5	938.4	2,452.9	1,479.1
Gross Realized Gains on Investment Sales		13.9	15	41.9	33.8
Gross Realized Losses on Investment Sales		6.5	$ 13.1	22.2	$ 22.8
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,230.8		2,230.8		2,106.4
Fair Value Measurements (Textuals)
Adjusted Cost of Debt Securities		913		913		771
Adjusted Cost of Domestic Equity Securities		588		588		555
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,763.4		1,763.4		2,157.7
Long Term Debt, Fair Value		2,213.4		2,213.4		2,472.7
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,286.2		1,286.2		1,286.1
Long Term Debt, Fair Value		1,502.6		1,502.6		1,402.9
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,674		2,674		2,273.5
Long Term Debt, Fair Value		2,943.4		2,943.4		2,417.2
Cash [Member]
Other Temporary Investments
Cost	[3]	159.2		159.2		271
Gross Unrealized Gains	[3]	0		0		0
Gross Unrealized Losses	[3]	0		0		0
Fair Value	[3],[4]	159.2		159.2		271
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Fair Value		975.6		975.6		811.2
Gross Unrealized Gains		62.8		62.8		40.2
Other-Than-Temporary Impairments		(3.4)		(3.4)		(4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		975.6		975.6		811.2
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		975.6		975.6		811.2
Gross Unrealized Gains		62.8		62.8		40.2
Other-Than-Temporary Impairments		(3.4)		(3.4)		(4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		975.6		975.6		811.2
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[5]	92.3		92.3		91.1
Gross Unrealized Gains	[5]	0.3		0.3		0
Gross Unrealized Losses	[5]	0		0		(0.7)
Fair Value	[5]	92.6		92.6		90.4
Domestic [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	1,220		1,220		1,126.9
Gross Unrealized Gains		631.6		631.6		571.6
Other-Than-Temporary Impairments		(78)		(78)		(79.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	1,220		1,220		1,126.9
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[6]	1,220		1,220		1,126.9
Gross Unrealized Gains		631.6		631.6		571.6
Other-Than-Temporary Impairments		(78)		(78)		(79.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	1,220		1,220		1,126.9
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		14.2		14.2		13.7
Gross Unrealized Gains		13.2		13.2		11.7
Gross Unrealized Losses		0		0		0
Fair Value	[6]	27.4		27.4		25.4
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	35.2		35.2		168.3
Gross Unrealized Gains		0		0		0
Other-Than-Temporary Impairments		0		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	35.2		35.2		168.3
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value	[7]	35.2		35.2		168.3
Gross Unrealized Gains		0		0		0
Other-Than-Temporary Impairments		0		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	35.2		35.2		168.3
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Fair Value		892.7		892.7		731.1
Gross Unrealized Gains		55.5		55.5		35.9
Other-Than-Temporary Impairments		(2.1)		(2.1)		(2.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		892.7		892.7		731.1
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		892.7		892.7		731.1
Gross Unrealized Gains		55.5		55.5		35.9
Other-Than-Temporary Impairments		(2.1)		(2.1)		(2.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		892.7		892.7		731.1
Corporate Debt [Member]
Nuclear Trust Fund Investments
Fair Value		66.5		66.5		57.9
Gross Unrealized Gains		6.1		6.1		3.2
Other-Than-Temporary Impairments		(1)		(1)		(1.1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		66.5		66.5		57.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		66.5		66.5		57.9
Gross Unrealized Gains		6.1		6.1		3.2
Other-Than-Temporary Impairments		(1)		(1)		(1.1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		66.5		66.5		57.9
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Fair Value		16.4		16.4		22.2
Gross Unrealized Gains		1.2		1.2		1.1
Other-Than-Temporary Impairments		(0.3)		(0.3)		(0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		16.4		16.4		22.2
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		16.4		16.4		22.2
Gross Unrealized Gains		1.2		1.2		1.1
Other-Than-Temporary Impairments		(0.3)		(0.3)		(0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		16.4		16.4		$ 22.2
Within One Year [Member]
Nuclear Trust Fund Investments
Fair Value		330.4		330.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		330.4		330.4
Within One Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		330.4		330.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		330.4		330.4
One Year To Five Year [Member]
Nuclear Trust Fund Investments
Fair Value		317.3		317.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		317.3		317.3
One Year To Five Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		317.3		317.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		317.3		317.3
Five Year To Ten Year [Member]
Nuclear Trust Fund Investments
Fair Value		150.4		150.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		150.4		150.4
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		150.4		150.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		150.4		150.4
After Ten Year [Member]
Nuclear Trust Fund Investments
Fair Value		177.5		177.5
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		177.5		177.5
After Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Fair Value		177.5		177.5
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		$ 177.5		$ 177.5
[1]	Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
[2]	Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
[3]	Primarily represents amounts held for the repayment of debt.
[4]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[5]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[6]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[7]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Fair Value Assets and Liabiliti

Fair Value Assets and Liabilities (Details) $ in Millions		3 Months Ended				9 Months Ended				12 Months Ended
		Sep. 30, 2016USD ($)$ / MWh		Sep. 30, 2015USD ($)		Sep. 30, 2016USD ($)$ / MWh		Sep. 30, 2015USD ($)		Dec. 31, 2015USD ($)$ / MWh
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 212.2				$ 212.2				$ 176.4
Other Temporary Investments		279.2				279.2				386.8
Risk Management Assets
Risk Management Assets		422.5				422.5				456.2
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,230.8				2,230.8				2,106.4
Total Assets		3,144.7				3,144.7				3,125.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities		319.3				319.3				266.2
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		149.3		$ 203.1		146.9		$ 150.8		150.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	34.2		11.1		42.1		13.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	12.3		6.2		45.5		54.3
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(34.4)		(2.1)		(16.7)		(3.8)
Purchases, Issuances and Settlements	[4]	(37.1)		(28.9)		(67.1)		(60.2)
Transfers into Level 3	[5],[6]	13.1		7.8		11.2		28.3
Transfers out of Level 3	[6],[7]	10		(5.4)		1.1		(17.1)
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	(29)		(25)		(64.6)		0.9
Ending Balance		98.4		166.8		$ 98.4		166.8		$ 146.9
Level 3 Quantitative Information
Counterparty Credit Risk	[9]									6.70%
Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					0.40%
High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					8.40%
Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					4.24%
Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	194.1				$ 194.1				$ 168.2
Other Temporary Investments		6.8				6.8				33.3
Risk Management Assets
Risk Management Assets		(208.4)				(208.4)				(286.9)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.5				16.5				7.8
Total Assets		9				9				(77.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities		(237.3)				(237.3)				(325.5)
Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	12.8				12.8				3.9
Other Temporary Investments		266.7				266.7				345.8
Risk Management Assets
Risk Management Assets		5.3				5.3				11.5
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238.7				1,238.7				1,287.4
Total Assets		1,523.5				1,523.5				1,648.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		10				10				24.1
Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	5.3				5.3				4.3
Other Temporary Investments		5.7				5.7				7.7
Risk Management Assets
Risk Management Assets		409.8				409.8				510.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Total Assets		1,396.4				1,396.4				1,334.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		429.2				429.2				493.8
Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Other Temporary Investments		0				0				0
Risk Management Assets
Risk Management Assets		215.8				215.8				220.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Total Assets		215.8				215.8				220.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		117.4				117.4				73.8
2016 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities										(9)
2016 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		1				1				2
2016 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		4				4				28
2017 - 2019 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(5)				(5)				(4)
2017 - 2019 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		5				5				18
2017 - 2019 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		36				36				29
2020 - 2021 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities										4
2020 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		22				22				19
2022 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(1)				(1)
2022 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals)
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		54				54				76
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11]	415.6	[12]			415.6	[12]			438.5	[13]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	270.3	[12]			270.3	[12]			236.6	[13]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11]	(203.7)	[12]			(203.7)	[12]			(287.7)	[13]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	(232.6)	[12]			(232.6)	[12]			(326.3)	[13]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11]	5.3	[12]			5.3	[12]			11.5	[13]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	10	[12]			10	[12]			24.1	[13]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11]	399.3	[12]			399.3	[12]			495	[13]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	394.2	[12]			394.2	[12]			471.5	[13]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11]	214.7	[12]			214.7	[12]			219.7	[13]
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	98.7	[12]			98.7	[12]			67.3	[13]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		207.5				207.5				212.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 103.7				$ 103.7				$ 70.3
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	10.19				10.19				9.69
Forward Price Range High | $ / MWh	[14]	143.84				143.84				165.36
Weighted Average Market Price | $ / MWh	[14]	43.20				43.20				36.35
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 8.3				$ 8.3				$ 8.4
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 13.7				$ 13.7				$ 3.5
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	(9.89)				(9.89)				(6.99)
Forward Price Range High | $ / MWh	[14]	10.63				10.63				10.34
Weighted Average Market Price | $ / MWh	[14]	0.73				0.73				1.10
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[11]	$ 6.6				$ 6.6				$ 17.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	48.5				48.5				26.1
Commodity Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11]	(5)				(5)				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	(5)				(5)				0.7
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	0				0				0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11]	10.5				10.5				15.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	34.8				34.8				18.9
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11]	1.1				1.1				1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11]	18.7				18.7				6.5
Interest Rate Foreign Currency Hedges [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2				0.2				0.4
Interest Rate Foreign Currency Hedges [Member] | Other [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2				0.2				0.4
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets		0.3				0.3				0.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.3				0.3				3.1
Fair Value Hedges [Member] | Other [Member]
Risk Management Assets
Risk Management Assets		0.3				0.3				0.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.3				0.3				0.1
Fair Value Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				3
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0				0				0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	7.9				7.9				14.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		11.3				11.3				30.6
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance	[15]	(12.9)		33.8		11.7		15.8		15.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3],[15]	22.7		5.1		25.5		1.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2],[15]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[15]	0		0		0		0
Purchases, Issuances and Settlements	[4],[15]	(17.9)		(14)		(36.2)		(16.1)
Transfers into Level 3	[5],[6]	0.1		0	[15]	0		0	[15]
Transfers out of Level 3	[6],[7],[15]	0		0		0.1		1.2
Changes in Fair Value Allocated to Regulated Jurisdiction	[8],[15]	0.9		(1.8)		(8.2)		20.5
Ending Balance	[15]	(7.1)		23.1		(7.1)		23.1		11.7
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0.1				0.1				0.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(7.6)				(7.6)				(10.5)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	7.8				7.8				14.8
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		7.8				7.8				15
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		8.3				8.3				13.9
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Risk Management Assets
Risk Management Assets		2.8				2.8				12.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		2.8				2.8				12.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities		9.9				9.9				0.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	3.4				3.4				15.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	11				11				4.9
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	(7.7)				(7.7)				(10.6)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	(7.7)				(7.7)				(13.6)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				0.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	8.3				8.3				13.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	8.8				8.8				17.8
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	2.8				2.8				12.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	9.9				9.9				0.5
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2.1				2.1				7.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2				$ 0.2				$ 0.2
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	16.51				16.51				12.61
Forward Price Range High | $ / MWh	[14]	47.42				47.42				47.24
Weighted Average Market Price | $ / MWh	[14]	34.85				34.85				32.38
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 0.7				$ 0.7				$ 4.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 9.7				$ 9.7				$ 0.3
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	(0.99)				(0.99)				(6.96)
Forward Price Range High | $ / MWh	[14]	10.63				10.63				8.43
Weighted Average Market Price | $ / MWh	[14]	1.94				1.94				1.34
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,230.8				$ 2,230.8				$ 2,106.4
Total Assets		2,236.2				2,236.2				2,118.7
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance	[15]	3.5		11.8		4.3		14.7		14.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3],[15]	3.8		0.9		7		(0.2)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2],[15]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	[15]	0		0		0		0
Purchases, Issuances and Settlements	[4],[15]	(5)		(3.6)		(10.3)		(12.8)
Transfers into Level 3	[5],[6],[15]	0		0		0		0
Transfers out of Level 3	[6],[7],[15]	0		0		0.1		0.8
Changes in Fair Value Allocated to Regulated Jurisdiction	[8],[15]	2.2		(2.7)		3.4		3.9
Ending Balance	[15]	4.5		6.4		4.5		6.4		4.3
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.5				16.5				7.8
Total Assets		10.6				10.6				(3.3)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,238.7				1,238.7				1,287.4
Total Assets		1,238.7				1,238.7				1,287.5
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Total Assets		982.2				982.2				828.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		4.7				4.7				6.3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Total Assets		4.7				4.7				6.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		0.2				0.2				2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	5.4				5.4				12.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	1.5				1.5				7.9
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	(5.9)				(5.9)				(11.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	(6.2)				(6.2)				(11.7)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				0.1
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0.1
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	6.6				6.6				17
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	7.5				7.5				17.5
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	4.7				4.7				6.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0.2				0.2				2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.6				1.6				6
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.2				$ 0.2				$ 0.2
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	16.51				16.51				12.61
Forward Price Range High | $ / MWh	[14]	47.42				47.42				47.24
Weighted Average Market Price | $ / MWh	[14]	34.85				34.85				32.38
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 3.1				$ 3.1				$ 0.3
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0				$ 0				$ 1.8
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	(9.89)				(9.89)				(6.96)
Forward Price Range High | $ / MWh	[14]	10.63				10.63				8.43
Weighted Average Market Price | $ / MWh	[14]	1.10				1.10				1.34
Ohio Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 16.2				$ 16.2				$ 27.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.2				16.2				46.9
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(14.6)		37.7		15.9		48.4		48.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(0.1)		0		(1.8)		1.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Purchases, Issuances and Settlements	[4]	0.9		0.3		4		(7.9)
Transfers into Level 3	[5],[6]	0		0		0		0
Transfers out of Level 3	[6],[7]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	(95.3)		(22.3)		(127.2)		(26)
Ending Balance		(109.1)		15.7		$ (109.1)		15.7		15.9
Ohio Power Co [Member] | Low [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					0.40%
Ohio Power Co [Member] | High [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					3.23%
Ohio Power Co [Member] | Weighted Average [Member]
Level 3 Quantitative Information
Counterparty Credit Risk	[10]					2.46%
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0.1				$ 0.1				27.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				0				30.9
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	16.1				16.1				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.1				16.1				0
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.1				0.1				0
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Risk Management Assets
Risk Management Assets		0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0				0				16
Liabilities, Fair Value Disclosure
Risk Management Liabilities		109.1				109.1
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				19.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	109.1				109.1				3.6
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	(0.1)				(0.1)				3.2
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	(0.1)				(0.1)				2.7
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0.1				0.1				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0.1				0.1				0.8
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				16
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	109.1				109.1				0.1
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0				0				16
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 109.1				$ 109.1				$ 0.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	24.38				24.38				41.61
Forward Price Range High | $ / MWh	[14]	78.45				78.45				165.36
Weighted Average Market Price | $ / MWh	[14]	52.45				52.45				86.84
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 1.1		1.7		$ 0.6		(0.3)		$ (0.3)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	0.4		(0.3)		(1)		(0.2)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Purchases, Issuances and Settlements	[4]	(0.7)		(0.2)		0.4		0.5
Transfers into Level 3	[5],[6]	0		0		0		0
Transfers out of Level 3	[6],[7]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	0.3		(0.2)		1.1		1
Ending Balance		1.1		1		1.1		1		0.6
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	1.1				1.1				0.6
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0.2
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	(0.2)				(0.2)				(0.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	(0.2)				(0.2)				(0.4)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0.1				0.1				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0.1				0.1				0.5
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	1.2				1.2				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0.1				0.1				0.1
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.2				1.2				0.7
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0.1				$ 0.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	(8.33)				(8.33)				(6.96)
Forward Price Range High | $ / MWh	[14]	1.02				1.02				8.43
Weighted Average Market Price | $ / MWh	[14]	(0.39)				(0.39)				1.34
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	$ 15.2				$ 15.2				$ 5.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		16.6				16.6				6
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		1.4		2		0.8		(0.5)		(0.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	4		2.4		7.7		9.2
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0		0
Purchases, Issuances and Settlements	[4]	(4.4)		(2.9)		(8.4)		(8.7)
Transfers into Level 3	[5],[6]	0		0		0		0
Transfers out of Level 3	[6],[7]	0		0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[8]	0.3		(0.2)		1.2		1.3
Ending Balance		1.3		$ 1.3		1.3		$ 1.3		0.8
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	2.4				2.4				1.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		2.3				2.3				1.5
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	12.8				12.8				3.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		12.8				12.8				3.6
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.1				0.1				0
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Cash and Cash Equivalents	[1]	0				0				0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		1.4				1.4				0.9
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	1.4				1.4				0.8
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				5.2
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	(0.1)				(0.1)				(0.1)
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	(0.1)				(0.1)				(0.4)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0				0				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	0.1				0.1				0
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0				0				5.5
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[11],[16]	1.4				1.4				0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities	[11],[16]	0.1				0.1				0.1
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1.4				1.4				0.9
Liabilities, Fair Value Disclosure
Risk Management Liabilities		$ 0.1				$ 0.1				$ 0.1
Level 3 Quantitative Information
Forward Price Range Low | $ / MWh	[14]	(8.33)				(8.33)				(6.96)
Forward Price Range High | $ / MWh	[14]	1.02				1.02				8.43
Weighted Average Market Price | $ / MWh	[14]	(0.39)				(0.39)				1.34
Cash [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1],[17]	$ 159.2				$ 159.2				$ 271
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	6.8				6.8				33.3
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	146.7				146.7				230
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	5.7				5.7				7.7
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[1]	0				0				0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		975.6				975.6				811.2
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[18]	92.6				92.6				90.4
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		92.6				92.6				90.4
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments		0				0				0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[19]	27.4				27.4				25.4
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[19]	0				0				0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[19]	27.4				27.4				25.4
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[19]	0				0				0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure
Other Temporary Investments	[19]	0				0				0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	35.2				35.2				168.3
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	16.5				16.5				7.8
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	18.7				18.7				160.5
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	0				0				0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	0				0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	35.2				35.2				168.3
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	16.5				16.5				7.8
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	18.7				18.7				160.5
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	0				0				0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[20]	0				0				0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		892.7				892.7				731.1
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		892.7				892.7				731.1
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		892.7				892.7				731.1
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		892.7				892.7				731.1
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		66.5				66.5				57.9
Corporate Debt [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		66.5				66.5				57.9
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		66.5				66.5				57.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		66.5				66.5				57.9
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.4				16.4				22.2
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.4				16.4				22.2
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.4				16.4				22.2
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		16.4				16.4				22.2
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0				0				0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	1,220				1,220				1,126.9
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0				0				0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	1,220				1,220				1,126.9
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0				0				0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	1,220				1,220				1,126.9
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	1,220				1,220				1,126.9
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	0				0				0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[19]	$ 0				$ 0				$ 0
[1]	Amounts in “Other’’ column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[2]	Included in revenues on the statements of income.
[3]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[4]	Represents the purchases, issuances and settlements 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 liabilities/assets.
[9]	Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[10]	Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[11]	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.’’
[12]	The September 30, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(5) million in periods 2017-2019; Level 2 matures $1 million in 2016, $5 million in periods 2017-2019 and $(1) million in periods 2022-2032; Level 3 matures $4 million in 2016, $36 million in periods 2017-2019, $22 million in periods 2020-2021 and $54 million in periods 2022-2032. Risk management commodity contracts are substantially comprised of power contracts.
[13]	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.
[14]	Represents market prices in dollars per MWh.
[15]	Includes both affiliated and nonaffiliated transactions.
[16]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[17]	Primarily represents amounts held for the repayment of debt.
[18]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[19]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[20]	Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Income Taxes (Details)

Income Taxes (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016USD ($)	Sep. 30, 2016USD ($)
Income Taxes (Textuals) [Abstract]
Valuation Allowance	$ 9	$ 9
Transmission and Distribution Expenses Net Income Adjustment		21
Certain Assets Held for Sale and 2015 Federal Income Tax Return
Income Taxes (Textuals) [Abstract]
Valuation Allowance Adjustment	$ 66
Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Transmission and Distribution Expenses Net Income Adjustment		2
Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Transmission and Distribution Expenses Net Income Adjustment		$ 9

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		9 Months Ended
		Nov. 01, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Long-term Debt
Senior Unsecured Notes							$ 13,629.1
Pollution Control Bonds			$ 1,724.5		$ 1,724.5		1,784.8
Notes Payable			268.5		268.5		264.7
Securitization Bonds			1,737.6		1,737.6		2,024
Spent Nuclear Fuel Obligation	[1]		266.1		266.1		265.6
Other Long-term Debt			1,768.9		1,768.9		1,604.5
Total Long-term Debt Outstanding			19,704.7		19,704.7		19,572.7
Long-term Debt Due Within One Year			2,384.8		2,384.8		1,831.8
Long-term Debt			17,319.9		17,319.9		17,740.9
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				1,570.3
Retirements and Principal Payments					1,307.6	$ 2,131.4
Short-term Debt:
Securitized Debt for Receivables	[3]		750		750		675
Commercial Paper			728.3		728.3		125
Total Short-term Debt			$ 1,478.3		$ 1,478.3		$ 800
Securitized Debt for Receivables	[3],[4]		0.65%		0.65%		0.30%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			0.73%	0.30%	0.65%	0.28%
Net Uncollectible Accounts Receivable Written Off			$ 7.7	$ 13.5	$ 17.5	$ 27.5
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			1,037.7		1,037.7		$ 924.8
Total Principal Outstanding			750		750		675
Delinquent Securitized Accounts Receivable			47.7		47.7		48.3
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable			27.8		27.8		17.5
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable			297.1		297.1		357.8
Financing Activities (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			309		309		$ 309
Repayments of Long-term Debt					1,307.6	2,131.4
Issuance of Long-term Debt	[2]				1,570.3
Reacquired Pollution Controls Bonds Held by Trustees			614		$ 614
Maximum Percentage Debt to Capitalization					67.50%
Total Commitment from Bank Conduits to Finance Receivables			750		$ 750
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Senior Unsecured Notes	[5]		14,073.9		14,073.9
Total Long-term Debt Outstanding	[5],[6]		19,839.5		19,839.5
Long-term Debt Due Within One Year	[5]		$ 2,519.6		$ 2,519.6
Commercial Paper [Member]
Short-term Debt:
Weighted Average Interest Rate	[4]		0.90%		0.90%		0.81%
AEP Subsidiaries [Member]
Long-term Debt
Long-term Debt Due Within One Year			$ 393.4		$ 393.4		$ 410.4
Long-term Debt			$ 1,727.6		1,727.6		1,971.4
AEP Subsidiaries [Member] | Notes Payable [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 5.1
Interest Rate (Variable)					Variable
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 5.1
Due Date					2,017
AEP Subsidiaries [Member] | Notes Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			5.75%		5.75%
Due Date					2,021
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.1
Interest Rate (Percentage)			5.75%		5.75%
Due Date					2,021
AEP Generating Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 7.3
Interest Rate (Percentage)			6.33%		6.33%
Due Date					2,037
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 7.3
Interest Rate (Percentage)			6.33%		6.33%
Due Date					2,037
AEP Generation Resources [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 60
Interest Rate (Variable)					Variable
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 60
Due Date					2,016
AEP Texas Central Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 100
Interest Rate (Variable)					Variable
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 100
Due Date					2,016
AEP Texas Central Co [Member] | OtherLongTermDebtTwo [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 125
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 125
Due Date					2,019
AEP Texas Central Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 44.2
Interest Rate (Percentage)			6.25%		6.25%
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 44.2
Interest Rate (Percentage)			6.25%		6.25%
Due Date					2,016
AEP Texas Central Co [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 149.1
Interest Rate (Percentage)			5.17%		5.17%
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 149.1
Interest Rate (Percentage)			5.17%		5.17%
Due Date					2,018
AEP Texas Central Co [Member] | Securitization Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 26.9
Interest Rate (Percentage)			0.88%		0.88%
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 26.9
Interest Rate (Percentage)			0.88%		0.88%
Due Date					2,017
AEP Texas North Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 75
Interest Rate (Variable)					Variable
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 75
Due Date					2,016
AEP Texas North Co [Member] | OtherLongTermDebtTwo [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 75
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 75
Due Date					2,019
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 4,033.1		$ 4,033.1		3,930.7
Long-term Debt Due Within One Year			503.1		503.1		318
Long-term Debt			3,530		3,530		3,612.7
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					213.6	672.5
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			131.9		131.9		135.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.6	2	5.4	6
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			361.7	355.3	1,071.6	1,115.5
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 213.6	$ 672.5
Maximum Percentage Debt to Capitalization					67.50%
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 286.9
Maximum Loans to Money Pool					25.7
Average Borrowings from Money Pool					165.5
Average Loans to Money Pool					24.9
Net Loans (Borrowings) to/from Money Pool			$ (59.7)		(59.7)
Authorized Short Term Borrowing Limit					$ 600
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%	0.59%
Minimum Interest Rate					0.69%	0.39%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					0.78%	0.46%
Average Interest Rate For Funds Loaned					0.79%	0.46%
Appalachian Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 125
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 125
Due Date					2,019
Appalachian Power Co [Member] | Pollution Control Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 125.3
Retirements and Principal Payments					$ 125.3
Interest Rate (Variable)					Variable
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 125.3
Issuance of Long-term Debt	[2]				$ 125.3
Due Date					2,016
Appalachian Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 65.4
Interest Rate (Percentage)			1.70%		1.70%
Due Date					2,020
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 65.4
Interest Rate (Percentage)			1.70%		1.70%
Due Date					2,020
Appalachian Power Co [Member] | Pollution Control Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 65.3
Interest Rate (Percentage)			2.25%		2.25%
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 65.3
Interest Rate (Percentage)			2.25%		2.25%
Due Date					2,016
Appalachian Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 23
Interest Rate (Percentage)			2.008%		2.008%
Due Date					2,024
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 23
Interest Rate (Percentage)			2.008%		2.008%
Due Date					2,024
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,407.4		$ 2,407.4		2,000
Long-term Debt Due Within One Year			176.1		176.1		162.9
Long-term Debt			2,231.3		2,231.3		1,837.1
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					76.8	$ 178.5
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			152.5		152.5		134.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2	2.2	5.6	6.6
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			448	401.5	1,220.2	1,192.1
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					76.8	$ 178.5
Reacquired Pollution Controls Bonds Held by Trustees			40		$ 40
Maximum Percentage Debt to Capitalization					67.50%
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 369.1
Maximum Loans to Money Pool					97.6
Average Borrowings from Money Pool					118.9
Average Loans to Money Pool					21.8
Net Loans (Borrowings) to/from Money Pool			$ (13.9)		(13.9)
Authorized Short Term Borrowing Limit					$ 500
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%	0.59%
Minimum Interest Rate					0.69%	0.39%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					0.73%	0.47%
Average Interest Rate For Funds Loaned					0.78%	0.46%
Indiana Michigan Power Co [Member] | Notes Payable [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.8
Interest Rate (Variable)					Variable
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.8
Due Date					2,016
Indiana Michigan Power Co [Member] | Notes Payable [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 16
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 16
Indiana Michigan Power Co [Member] | Notes Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.5
Interest Rate (Percentage)			2.12%		2.12%
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.5
Interest Rate (Percentage)			2.12%		2.12%
Due Date					2,016
Indiana Michigan Power Co [Member] | Notes Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 12.6
Interest Rate (Variable)					Variable
Due Date					2,017
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 12.6
Due Date					2,017
Indiana Michigan Power Co [Member] | Notes Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 24.8
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 24.8
Due Date					2,019
Indiana Michigan Power Co [Member] | Notes Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 31
Interest Rate (Variable)					Variable
Due Date					2,019
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 31
Due Date					2,019
Indiana Michigan Power Co [Member] | Notes Payable Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 6.1
Interest Rate (Variable)					Variable
Due Date					2,020
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 6.1
Due Date					2,020
Indiana Michigan Power Co [Member] | Notes Payable Seven [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 87.9
Interest Rate (Variable)					Variable
Due Date					2,020
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 87.9
Due Date					2,020
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 1
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,025
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 1
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,025
Indiana Michigan Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 400
Interest Rate (Percentage)			4.55%		4.55%
Due Date					2,046
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 400
Interest Rate (Percentage)			4.55%		4.55%
Due Date					2,046
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,763.4		$ 1,763.4		2,157.7
Long-term Debt Due Within One Year			46.4		46.4		395.9
Long-term Debt			1,717		1,717		1,761.8
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					395.9	$ 131.5
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			407.1		407.1		351.4
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			8.1	8.5	23.4	23.2
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			750.9	670.7	2,011.2	1,949
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					395.9	$ 131.5
Reacquired Pollution Controls Bonds Held by Trustees			345		345
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					227.9
Maximum Loans to Money Pool					379.2
Average Borrowings from Money Pool					137.8
Average Loans to Money Pool					251.1
Net Loans (Borrowings) to/from Money Pool			$ 0.2		0.2
Authorized Short Term Borrowing Limit					$ 400
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%	0.59%
Minimum Interest Rate					0.69%	0.39%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					0.85%	0.00%
Average Interest Rate For Funds Loaned					0.74%	0.47%
Ohio Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.1
Interest Rate (Percentage)			1.149%		1.149%
Due Date					2,028
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.1
Interest Rate (Percentage)			1.149%		1.149%
Due Date					2,028
Ohio Power Co [Member] | Securitization Bonds [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 45.8
Interest Rate (Percentage)			0.958%		0.958%
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 45.8
Interest Rate (Percentage)			0.958%		0.958%
Due Date					2,018
Ohio Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 350
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 350
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,016
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,286.2		$ 1,286.2		1,286.1
Long-term Debt Due Within One Year			125.5		125.5		275.4
Long-term Debt			1,160.7		1,160.7		1,010.7
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					150.3	$ 0.3
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			146.1		146.1		116.1
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1.8	1.7	4.7	4.5
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			390.6	411.5	971.9	1,025.9
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 150.3	$ 0.3
Maximum Percentage Debt to Capitalization					67.50%
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 9.6
Maximum Loans to Money Pool					205.4
Average Borrowings from Money Pool					5.1
Average Loans to Money Pool					47
Net Loans (Borrowings) to/from Money Pool			$ 51.1		51.1
Authorized Short Term Borrowing Limit					$ 300
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%	0.59%
Minimum Interest Rate					0.69%	0.39%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					0.76%	0.49%
Average Interest Rate For Funds Loaned					0.81%	0.46%
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 0.3
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,027
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 0.3
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,027
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 50
Interest Rate (Percentage)			3.05%		3.05%
Due Date					2,026
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 50
Interest Rate (Percentage)			3.05%		3.05%
Due Date					2,026
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 100
Interest Rate (Percentage)			4.11%		4.11%
Due Date					2,046
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 100
Interest Rate (Percentage)			4.11%		4.11%
Due Date					2,046
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 150
Interest Rate (Percentage)			6.15%		6.15%
Due Date					2,016
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 150
Interest Rate (Percentage)			6.15%		6.15%
Due Date					2,016
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,674		$ 2,674		2,273.5
Long-term Debt Due Within One Year			354		354		3.3
Long-term Debt			2,320		2,320		2,270.2
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					3.3	$ 306.8
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			170		170		$ 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2.1	2	5.3	5.3
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			460.4	$ 468	1,183.9	1,222.3
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 3.3	$ 306.8
Maximum Percentage Debt to Capitalization					67.50%
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Borrowings from Money Pool					$ 249.4
Maximum Loans to Money Pool					308.2
Average Borrowings from Money Pool					171.8
Average Loans to Money Pool					302.8
Net Loans (Borrowings) to/from Money Pool			297.4		297.4
Authorized Short Term Borrowing Limit					$ 350
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%	0.59%
Minimum Interest Rate					0.69%	0.39%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Borrowed					0.79%	0.46%
Average Interest Rate For Funds Loaned					0.91%	0.48%
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract]
Maximum Loans to Money Pool					$ 2
Average Loans to Money Pool					2
Net Loans To Borrowings From Nonutility Money Pool			$ 2		$ 2
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.91%
Minimum Interest Rate					0.69%
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract]
Average Interest Rate For Funds Loaned					0.79%
Southwestern Electric Power Co [Member] | Notes Payable [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 3.3
Interest Rate (Percentage)			4.58%		4.58%
Due Date					2,032
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt					$ 3.3
Interest Rate (Percentage)			4.58%		4.58%
Due Date					2,032
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 5.2
Interest Rate (Percentage)			3.50%		3.50%
Due Date					2,023
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 5.2
Interest Rate (Percentage)			3.50%		3.50%
Due Date					2,023
Southwestern Electric Power Co [Member] | Senior Unsecured Notes [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 400
Interest Rate (Percentage)			2.75%		2.75%
Due Date					2,026
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 400
Interest Rate (Percentage)			2.75%		2.75%
Due Date					2,026
Transource Missouri [Member] | Other Long Term Debt [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				$ 11.5
Interest Rate (Variable)					Variable
Due Date					2,018
Financing Activities (Textuals) [Abstract]
Issuance of Long-term Debt	[2]				$ 11.5
Due Date					2,018
[1]	Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2016 and December 31, 2015, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.
[2]	Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
[3]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[4]	Weighted average rate.
[5]	Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.
[6]	Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended			12 Months Ended
	Sep. 30, 2016		Sep. 30, 2015	Sep. 30, 2016		Sep. 30, 2015	Dec. 31, 2015
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	$ 1,737.6			$ 1,737.6			$ 2,024
Securitized Transition Assets	1,559			$ 1,559			1,749.9
Percentage of 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	15		$ 13	$ 28		$ 27
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Assets [Member]
ASSETS
Assets	179.4			179.4			165.3
Protected Cell Of Energy Insurance Services, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0			0			0
Protected Cell Of Energy Insurance Services, Inc. [Member] | Other Non Current Assets [Member]
ASSETS
Assets	1.7			1.7			1.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	181.1			181.1			167.2
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	47.7			47.7			41.8
Protected Cell Of Energy Insurance Services, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	91.1			91.1			83.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	42.3			42.3			41.5
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	181.1			181.1			167.2
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution				38			47
Transource Energy [Member] | Current Assets [Member]
ASSETS
Assets	12.2			12.2			10.8
Transource Energy [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	298.5			298.5			227.2
Transource Energy [Member] | Other Non Current Assets [Member]
ASSETS
Assets	5.5			5.5			5.5
Transource Energy [Member] | Total Assets [Member]
ASSETS
Assets	316.2			316.2			243.5
Transource Energy [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	35.4			35.4			36.6
Transource Energy [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	127.2			127.2			113
Transource Energy [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	153.6			153.6			93.9
Transource Energy [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	316.2			$ 316.2			243.5
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	1,038.7			$ 1,038.7			925.7
AEP Credit, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0			0			0
AEP Credit, Inc. [Member] | Other Non Current Assets [Member]
ASSETS
Assets	10.3			10.3			6.4
AEP Credit, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	1,049			1,049			932.1
AEP Credit, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	948.2			948.2			855.1
AEP Credit, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.6			0.6			0.3
AEP Credit, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	100.2			100.2			76.7
AEP Credit, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 1,049			$ 1,049			932.1
PATH West Virginia Transmission Co, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of Debt Capital Structure in PATH's Stipulation Agreement	50.00%			50.00%
Percentage of Equity Capital Structure in PATH's Stipulation Agreement	50.00%			50.00%
Percentage of Cost of Long Term Debt for PATH's Stipulation Agreement	4.70%			4.70%
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 Consolidated Balance Sheet	$ 18.8			$ 18.8			18.8
Maximum Exposure	18.8			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 Consolidated Balance Sheet	2.2			2.2			2.2
Maximum Exposure	2.2			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 Consolidated Balance Sheet	21			21			21
Maximum Exposure	21			21			21
AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	1,300			1,300			1,500
Securitized Transition Assets	1,100			1,100			1,300
AEP Texas Central Transition Funding Co [Member] | Current Assets [Member]
ASSETS
Assets	163.5			163.5			234.1
AEP Texas Central Transition Funding Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0			0			0
AEP Texas Central Transition Funding Co [Member] | Other Non Current Assets [Member]
ASSETS
Assets	1,210.4	[1]		1,210.4	[1]		1,365.7	[2]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	62.9			62.9			68.2
AEP Texas Central Transition Funding Co [Member] | Total Assets [Member]
ASSETS
Assets	1,373.9			1,373.9			1,599.8
AEP Texas Central Transition Funding Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	242.6			242.6			291.7
AEP Texas Central Transition Funding Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1,113.2			1,113.2			1,290
AEP Texas Central Transition Funding Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	18.1			18.1			18.1
AEP Texas Central Transition Funding Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 1,373.9			$ 1,373.9			1,599.8
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	13.50%			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]
Securitized Transition Assets	$ 311			$ 311			328
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	55.3		63.7	165.7		164.7
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 Consolidated Balance Sheet	20			20			25.8
Maximum Exposure	20			20			25.8
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	319			319			342
Securitized Transition Assets	311			311			328
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Assets [Member]
ASSETS
Assets	11.8			11.8			18.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0			0			0
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Other Non Current Assets [Member]
ASSETS
Assets	314.7	[3]		314.7	[3]		332	[4]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	3.8			3.8			4
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Assets [Member]
ASSETS
Assets	326.5			326.5			350.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	25			25			27.1
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	300.2			300.2			321.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.3			1.3			1.9
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	326.5			326.5			350.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals) [Abstract]
Payments Made by I&M to DCC Fuel	23		29	77		86
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Assets [Member]
ASSETS
Assets	109.2			109.2			91.1
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	165.9			165.9			159.9
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Other Non Current Assets [Member]
ASSETS
Assets	78.8			78.8			84.6
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Assets [Member]
ASSETS
Assets	353.9			353.9			335.6
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	98.2			98.2			84.8
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	255.7			255.7			250.8
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0			0			0
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	353.9			353.9			335.6
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	32.7		37.5	97.7		102.1
Indiana Michigan Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	65		67	166		182
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 Consolidated Balance Sheet	11			11			16.6
Maximum Exposure	11			11			16.6
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 Consolidated Balance Sheet	17			17			17
Ohio Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitized Transition Assets	68			68			85.9
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	39.4		48.5	123.2		128.6
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 Consolidated Balance Sheet	13.9			13.9			23.3
Maximum Exposure	13.9			13.9			23.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	140			140			185
Securitized Transition Assets	68			68			86
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Assets [Member]
ASSETS
Assets	18.9			18.9			31.2
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0			0			0
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Other Non Current Assets [Member]
ASSETS
Assets	128.1	[5]		128.1	[5]		162	[6]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	60.2			60.2			76.1
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Assets [Member]
ASSETS
Assets	147			147			193.2
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	46.9			46.9			47.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	98.8			98.8			144.6
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.3			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	147			147			193.2
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	23.6		29.9	77.1		77.8
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 Consolidated Balance Sheet	7.8			7.8			12.6
Maximum Exposure	7.8			7.8			12.6
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	42		41	127		124
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Assets [Member]
ASSETS
Assets	61.8			61.8			61.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	123.6			123.6			147
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Other Non Current Assets [Member]
ASSETS
Assets	63.9			63.9			61.8
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Assets [Member]
ASSETS
Assets	249.3			249.3			270.5
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	32			32			47.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	217			217			222.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.3			0.3			0.5
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	249.3			249.3			270.5
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Consolidated Balance Sheet	20.3			20.3			15.3
Maximum Exposure	113			113			98.2
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	15		30	$ 43		59
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 Consolidated Balance Sheet	7.6			$ 7.6			7.6
Maximum Exposure	7.6			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 Consolidated Balance Sheet	12.7			12.7			7.7
Maximum Exposure	12.7			12.7			7.7
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 Consolidated Balance Sheet	0			0			0
Maximum Exposure	92.7			92.7			82.9
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	31.4		$ 39.2	101.2		$ 102.6
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 Consolidated Balance Sheet	11.8			11.8			16.4
Maximum Exposure	$ 11.8			$ 11.8			$ 16.4
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%			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%			50.00%
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	100.00%			100.00%
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	86.50%			86.50%
[1]	Includes an intercompany item eliminated in consolidation of $62.9 million.
[2]	Includes an intercompany item eliminated in consolidation of $68.2 million.
[3]	Includes an intercompany item eliminated in consolidation of $3.8 million.
[4]	Includes an intercompany item eliminated in consolidation of $4.0 million.
[5]	Includes an intercompany item eliminated in consolidation of $60.2 million.
[6]	Includes an intercompany item eliminated in consolidation of $76.1 million.